SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
X ACT OF 1934
For the fiscal year ended December 31, 1999
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ___________________ to __________________
Commission File Number 1-7978
BLACK HILLS CORPORATION
Incorporated in South Dakota IRS Identification Number 46-0111677
625 Ninth Street
Rapid City, South Dakota 57701
Registrant's telephone number, including area code
(605) 721-1700
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Common stock of $1.00 par value New York Stock Exchange
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
YES X NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
X
State the aggregate market value of the voting stock held by non-affiliates of
the Registrant.
At January 31, 2000 $511,580,784
Indicate the number of shares outstanding of each of the Registrant's classes of
common stock, as of the latest practicable date.
Class Outstanding at January 31, 2000
Common stock, $1.00 par value 21,371,521 shares
Documents Incorporated by Reference
1. Definitive Proxy Statement of the Registrant filed pursuant to Regulation
14A for the 2000 Annual Meeting of Stockholders to be held on June 20,
2000, is incorporated by reference in Part III.
TABLE OF CONTENTS
Page
ITEM 1. BUSINESS........................................................4
GENERAL....................................................4
ELECTRIC POWER SUPPLY......................................4
ELECTRIC SERVICE TERRITORY AND SALES.......................6
COMPETITION IN THE ELECTRIC UTILITY BUSINESS...............7
INDEPENDENT ENERGY OPERATIONS.............................11
COMMUNICATIONS OPERATIONS.................................12
ENVIRONMENTAL REGULATION..................................13
EMPLOYEES.................................................16
ITEM 2. PROPERTIES.....................................................16
ELECTRIC PROPERTIES.......................................16
INDEPENDENT ENERGY PROPERTIES.............................17
COMMUNICATIONS PROPERTIES.................................18
ITEM 3. LEGAL PROCEEDINGS..............................................18
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............18
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS............................................19
ITEM 6. SELECTED FINANCIAL DATA........................................19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS............................20
LIQUIDITY AND CAPITAL RESOURCES...........................20
MARKET RISK DISCLOSURES...................................22
RATE REGULATION...........................................25
RESULTS OF OPERATIONS.....................................26
BUSINESS OUTLOOK STATEMENTS...............................31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA....................33
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE.........................55
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.............55
ITEM 11. EXECUTIVE COMPENSATION.........................................56
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.56
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................56
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.56
SIGNATURES.....................................................59
DEFINITIONS
When the following terms are used in the text they will have the meanings
indicated.
Term Meaning
- ---- -------
Black Hills Power...........................Black Hills Power and Light Company, the assumed business name of
the Company under which its electric operations are conducted
Basin Electric..............................Basin Electric Power Cooperative, Inc., a rural electric cooperative
engaged in generating and transmitting electric power to its member
RECs
Black Hills Capital Group...................Black Hills Capital Group, Inc., a wholly owned subsidiary of Wyodak
Resources
Black Hills Exploration and Production......Black Hills Exploration and Production, Inc., a wholly owned subsidiary of Wyodak
Resources
Company.....................................Black Hills Corporation
DEQ.........................................Department of Environmental Quality of the State of Wyoming
FERC........................................Federal Energy Regulatory Commission
MDU.........................................Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.
NS #1.......................................Neil Simpson Unit #1, a 20 megawatt coal-fired electric generating
plant owned by the Company and located adjacent to the Wyodak
Plant and Neil Simpson Unit #2
NS #2.......................................Neil Simpson Unit #2, an 80 megawatt coal-fired electric generating
plant owned by the Company and located adjacent to the Wyodak
Plant and Neil Simpson Unit #1
Pacific Power...............................PacifiCorp, which operates its electric utility operations under the
assumed names of Pacific Power and Utah Power
RECs........................................Rural electric cooperatives, which are owned by their customers and
which rely primarily on the United States for their financing needs
SDPUC.......................................The South Dakota Public Utilities Commission
WAPA........................................Western Area Power Administration, an agency of the Department of
Energy of the United States of America
WPSC........................................The Wyoming Public Service Commission
Wyodak Resources............................Wyodak Resources Development Corp., a wholly owned subsidiary of
the Company
Wyodak Plant................................A 330 megawatt coal-fired electric generating plant which is owned 20
percent by the Company and 80 percent by Pacific Power and located
near Gillette, Wyoming
PART I
ITEM 1. BUSINESS
GENERAL
Incorporated under the laws of South Dakota in 1941, the Company is an energy
and communications company primarily consisting of three principal business
units: regulated electric, independent energy and communications. The Company's
mission statement is to provide quality energy and communications products and
services at competitive prices in targeted markets to build value for
shareholders and customers and create opportunities for employees. The Company
operates its public utility electric operations under the assumed name of Black
Hills Power and Light Company; operates its independent energy businesses
through its direct and indirect subsidiaries: Wyodak Resources related to coal,
Black Hills Exploration and Production related to oil and natural gas, energy
marketing through Enserco Energy, Inc. related to natural gas, Black Hills
Energy Resources, Inc. related to crude oil and Black Hills Coal Network, Inc.
related to coal, and independent power activities though Black Hills Generation
and Black Hills Energy Capital, all consolidated for reporting purposes as Black
Hills Energy Ventures and, operates communication operations through Black Hills
Fiber Systems, Inc., Black Hills FiberCom, LLC and DAKSOFT, Inc.
Black Hills Power is engaged in the generation, purchase, transmission,
distribution and sale of electric power and energy to approximately 57,700
customers in 11 counties in western South Dakota, northeastern Wyoming and
southeastern Montana, an area with a population estimated at 165,000. The
largest community served is Rapid City, South Dakota, a major retail, wholesale
and health care center, with a population, including environs, estimated at
75,000. Agriculture, tourism, small stakes gambling, mining, lumbering, small
item manufacturing, service and support businesses and government support
through Ellsworth Air Force Base are the primary influences on the economic
well-being of the region.
Black Hills Energy Ventures is engaged in the mining and sale of low sulfur
sub-bituminous coal near Gillette, Wyoming, in the Powder River Basin; has oil
and gas exploration and production operations with interests located in the
Rocky Mountain region, Texas, California and various other locations; markets
natural gas, crude oil and coal to the East Coast, Midwest, Southwest, Rocky
Mountain, Northwest and West Coast regions and owns interests in independent
power production facilities in the Rocky Mountain region. Communications
operations provide local and long-distance telephone, cable television, internet
and data services in the Black Hills of South Dakota, and development and
marketing of software products for the utility and communications industries.
Black Hills Capital Group directs the Company's corporate development efforts
primarily in the energy and communications areas.
Information as to the continuing lines of business of the Company for the
calendar years 1999-1997 is as follows:
1999 1998 1997
---- ---- ----
(in thousands)
Revenue from sales
to unaffiliated customers:
Electric $132,799 $128,834 $126,194
Independent energy 650,711 539,762 176,076
Communications 278 - -
Revenue from
inter-company sales:
Electric $ 423 $ 402 $ 303
Independent
energy 7,664 10,256 11,089
For additional information relating to the Company's operations by business line
see Note 11 of "NOTES TO CONSOLIDATED FINANCIAL STATEMENTS."
ELECTRIC POWER SUPPLY
General
- -------
Black Hills Power has been able to meet the needs of its customers for electric
power and energy through its owned generating capacity and by contract
purchases. Black Hills Power's peak load of 361 megawatts was reached in July
1999. Black Hills Power is a member of a power pool, the Rocky Mountain Reserve
Group. Black Hills Power's 1999 reserve requirement, and estimated 2000 reserve
requirement, is 20 megawatts, consisting of 10 megawatts of spinning reserves
and 10 megawatts of secondary reserves.
Black Hills Power owns coal-fired generating units having a summer capability
rating of 214 megawatts and 77 megawatts of oil-fired diesel and natural
gas-fired combustion turbines for peaking and standby use. In addition, Black
Hills Power is currently constructing a 40 megawatt natural gas-fired combustion
turbine for additional peaking resources and load growth. Black Hills Power
purchases additional resources under three contracts with Pacific Power: the
Power Sales Agreement, under which it purchases 75 megawatts of baseload power
declining to 50 megawatts from 2000 to 2004; the Reserve Capacity Integration
Agreement, under which 33 megawatts of additional reserve capacity are
available; and the Capacity Contract, under which Black Hills Power has options
to be exercised seasonally to purchase up to 60 megawatts of capacity.
Pacific Power's Power Sales Agreement
- -------------------------------------
This agreement obligates Black Hills Power to purchase from Pacific Power 75
megawatts of electric power plus energy at a load factor varying from a minimum
of 41 percent to a maximum of 80 percent as scheduled by Black Hills Power. In
October 1997, Black Hills Power entered into a second Restated and Amended Power
Sales Agreement with Pacific Power. The Amended Agreement reduces the contract
capacity by 25 megawatts (5 megawatts per year beginning in 2000). The contract
terminates December 31, 2023. The power and energy delivered is power from
Pacific Power's system and does not depend on any one unit, but the price is
generally based on Pacific Power's costs in Units 3 and 4 of the Colstrip
coal-fired generating plant near Colstrip, Montana. Black Hills Power contracts
for transmission service from Pacific Power under Pacific Power's FERC approved
transmission rates. The Company has incurred average capacity charges of $14,400
per megawatt month and energy charges of $11.46 per megawatt hour over the last
three years of this agreement with a 70 percent load factor for a total per
megawatt hour cost of $34.47.
Pacific Power's Reserve Capacity Integration Agreement
- ------------------------------------------------------
This agreement obligates Pacific Power until the end of the contract in 2012 to
make available to Black Hills Power 100 megawatts of reserve capacity to be
acquired by Black Hills Power only at such time under prudent utility practice
Black Hills Power would have operated its combustion turbines. In return,
Pacific Power has the right to utilize Black Hills Power's four 25 megawatt
combustion turbines (with a summer rating of 67 megawatts), but Black Hills
Power has a prior right to use said turbines to support the transmission system.
The price for any energy Black Hills Power acquires under this agreement is
based upon the lower of Pacific Power's incremental costs of generation of its
highest priced coal-fired plant or the cost of fuel to operate the combustion
turbines. Pacific Power also pays certain operating and maintenance expenses of
the combustion turbines, together with a $50,000 payment per month for the
remaining life of the contract.
Pacific Power's Capacity Contract
- ---------------------------------
Under this contract, Pacific Power granted Black Hills Power an option to be
exercised for each six-month season for a period commencing October 1, 1996 and
ending March 31, 2007 to purchase up to 60 megawatts of peaking capacity at
established prices. Black Hills Power may schedule the energy at a rate up to
100 percent per hour at a load factor up to 15 percent per season. Other than to
give preference to purchasing peaking capacity from Pacific Power, Black Hills
Power is under no obligation to exercise any of the six-month seasonal options.
In addition to granting Black Hills Power options to purchase peaking capacity,
the Pacific Power Capacity Contract also obligates Black Hills Power to sell to
Pacific Power until December 31, 2000, all surplus energy which is defined as
the difference in Black Hills' Resources (all energy from Black Hills Power's
generating resources and energy entitlement under Pacific Power's Power Sales
Agreement) and Black Hills' Loads (non-end user contracts of five months or
longer and all retail customers as they exist from time to time). The selling
prices are based upon economy energy spot price indices determined daily in the
western part of the United States with a sharing between Pacific Power and Black
Hills Power of prices above certain levels. Black Hills Power is not obligated
to sell any energy below its marginal production cost. The contract also
provides Black Hills Power an option to store energy with Pacific Power and to
take that energy back for the purpose of replacing energy from a forced or
scheduled outage of NS #2 or Black Hills Power's share of the Wyodak Plant.
To the extent of the excess capacity and energy available to Black Hills Power
from its generating resources and the Pacific Power purchased power contracts,
Black Hills Power at this time has the flexibility to serve the expected growth
of its loads in its service territory and as opportunities arise in the
meantime, to increase sales of its energy and capacity.
ELECTRIC SERVICE TERRITORY AND SALES
Retail Service Territory
- ------------------------
Black Hills Power's service territory is currently protected by assigned service
area and franchises that generally grant to Black Hills Power the exclusive
right to sell all electric power consumed therein, subject to providing adequate
service.
As evidenced by a 1 percent increase in customers in both 1999 and 1998, the
economy in and around Black Hills Power's service territory is believed by
management to be stable. Small businesses and regional plant expansions are
continually being attracted to the region along with retirees who have
discovered the Black Hills region with its scenery, recreational activities and
medical services to be an attractive place to live. Management anticipates that
the economy will continue to experience modest growth, but can give no
assurances, as many economic factors will greatly influence any economy.
Ellsworth Air Force Base, a B-1 bomber military base near Rapid City, survived
the fourth round of base closures in 1995 but may be subject to future base
closures that are beyond the Company's control. The Company does not serve the
air base, but the base impacts the surrounding economy. In January 1998,
Homestake Mining Company (Homestake), the Company's third largest customer at
4.3 percent of 1999 electric revenues, announced a reorganization and
restructuring plan at its gold mine in Lead, South Dakota. Load reductions at
Homestake were mitigated by additional off-system wholesale sales. Other major
industries in and around Black Hills Power's service territory have been
economically stable.
Wholesale to City of Gillette
- -----------------------------
Black Hills Power sells electric power and energy to the municipal electric
system at Gillette, Wyoming. Service is rendered under a long-term contract,
amended in 1998, and expiring July 1, 2012, wherein Black Hills Power sells to
the City of Gillette its first 23 megawatts of capacity requirements and the
associated energy. In 1998, as part of a contract amendment, the transmission
service component was unbundled from the power supply agreement, and
transmission service will be provided at FERC approved rates. In the amended
contract, the City of Gillette has agreed not to apply to FERC for any rate
change to be effective prior to January 1, 2003, unless and in the event that
Black Hills Power files for a rate change with FERC, which rate filing cannot be
effective prior to January 1, 2002, except under extraordinary events as defined
in the contract. In addition, Black Hills Power agreed to phase in price
reductions for the power purchased by the City of Gillette. The most recent
average annual capacity factor for this 23 megawatt demand has been
approximately 92 percent. Sales to Gillette represented 9.6 percent and 9.5
percent of total firm energy sales and 5.9 percent and 6.1 percent of revenue
from total firm electric sales in 1999 and 1998, respectively.
Wholesale to MDU
- ----------------
Black Hills Power and MDU entered into a Power Integration Agreement, dated as
of September 9, 1994, providing for the sale to MDU of up to 55 megawatts of
power and associated energy to serve MDU's Sheridan, Wyoming, electric service
territory for a period of 10 years which commenced January 1, 1997. The MDU
Sheridan service territory has experienced a 47 megawatt winter peak and
operates at a 57 percent load factor.
The agreement provides for fixed rates for capacity and energy to be paid by MDU
during the 10-year contract term. Black Hills Power and MDU have agreed not to
apply to FERC for any rate changes in the contract for the entire 10-year term
other than increases caused by governmental direct taxes on electric generation
fired by hydrocarbons. The agreement further provides for Black Hills Power and
MDU to equally share the costs of constructing a combustion turbine of
approximately 70 megawatts at such time during the 10-year term that Black Hills
Power determines in its sole discretion that such turbine is required. While
Black Hills Power has begun construction of a 40 megawatt gas-fired combustion
turbine, and approached MDU with the right of participation in such
construction, MDU has declined participation in this project.
Additional Off-System Sales
- ---------------------------
Black Hills Power sold 445,700, 371,100 and 279,600 megawatt hours of
non-firm energy in 1999, 1998 and 1997 respectively. The selling price is based
on spot market prices.
Transmission Service Sales
- --------------------------
Black Hills Power furnishes long-term transmission services under two contracts:
(i) the transmission contract terminating December 31, 2020 (1986 Agreement),
among Black Hills Power and Basin Electric and the other distribution
cooperatives as it concerns the transmission contract (the Cooperatives) and
(ii) the agreement with the City of Gillette terminating July 1, 2012 (described
under Wholesale to City of Gillette above), under which Black Hills Power has
agreed to deliver all of the City of Gillette's electric requirements. The rates
charged under the transmission contract with the Cooperatives are fixed formula
rates, and the transmission rates under the Gillette contract are established by
FERC under Black Hills Power's open access transmission tariff.
In 1998, the FERC approved a settlement in Black Hills' Order 888 open access
transmission tariff filing. This settlement allows Black Hills to use the
revenues received under the long-term transmission agreement between the Company
and the Cooperatives which terminates on December 31, 2020 as being equal to the
cost of providing service to the Cooperatives. The Cooperatives' transmission
loads are not considered when calculating Black Hills' open access transmission
tariff rates; and as such, the Cooperatives are paying less than their fully
allocated cost for use of the transmission system. But as a result of allowing
the revenue credit methodology, the open access transmission rates still allow
Black Hills to earn a just and reasonable rate on its transmission facilities.
The settlement with the FERC is consistent with past actions of the SDPUC and
WPSC, which similarly have allowed Black Hills to use the revenue credit
methodology in determining bundled rates for retail customers.
Finally, to the extent that a transmission customer (other than Black Hills
Power or the Cooperatives) arranges for transmission service on the
Cooperatives' transmission facilities as defined in the 1986 Agreement for the
purposes of serving the transmission customer's retail customers within the
joint transmission area as defined within the 1986 Agreement, Black Hills Power
shall provide a credit, not to exceed its tariff rate, against their rates for
transmission service it charges to such transmission customer for its use of the
Cooperatives' transmission facilities to serve the transmission customer's
retail customers within the joint transmission area.
Black Hills Power does not anticipate any material use of its transmission
system by third-parties until such time that retail wheeling may be instituted.
It is uncertain at this date as to what extent the FERC or the state regulatory
jurisdictions will have jurisdiction over determining retail wheeling rates.
COMPETITION IN THE ELECTRIC UTILITY BUSINESS
Long-Term Contracts
- -------------------
In 1998, Black Hills Power initiated an effort to enter into new contracts with
its largest industrial customers. During 1999, this effort was expanded to cover
most of Black Hills Power's larger commercial and industrial accounts. The
contracting effort had two parts, the first being customer specific negotiations
with industrial customers with loads greater than 5 MW. These customers
typically were being served under contracts that had matured to the point where
the customer could exercise its right to extend the contract annually to in
effect have a three-year remaining term (right-to-extend term).
Part two of the effort was the design and approval by the SDPUC of the new
General Service Large-Optional Combined Account Billing tariff. This tariff
allows customers with multiple accounts eligible for the General Service Large
tariff to aggregate these loads prior to billing under a declining block rate
schedule modeled after the existing General Service Large rate.
A key provision of the new tariff and large industrial contracts is the
agreement of the customer to grant Black Hills Power a five-year right to
continue to serve the customer if deregulation occurs (meet or release
contracts). This right is essentially an option to serve the customer's firm
power requirements at market prices.
As of February 2000, Black Hills Power has replaced all but two of the 1995 rate
case "right-to-extend term" contracts with the "meet or release" approach. Of
the two remaining contracts, the largest customer (approximately 5 MW) is
expected to sign a five-year fixed term contract, while the other customer is a
curtailable load that was not targeted for the new contract. The new contracts
cover 6 large industrial customers representing 62 MW of load.
In addition, Black Hills Power was successful in implementing the new General
Service Large-Optional Combined Account Billing tariff. In all, 22 customers,
representing 104 accounts and 33 MW of the 40 MW of estimated eligible load,
have elected service and signed contracts under the new tariff.
Business Development Rates
- --------------------------
Both the SDPUC and the WPSC authorized Black Hills Power to negotiate rates
above its marginal costs but below full cost with any customer with a load of
over 250 KVA if that customer has a legal choice of its electric supplier. Black
Hills Power expects to utilize this tariff in those instances where a new
business would have a choice of locating in the service territory of either
Black Hills Power or a competing REC or enticing a new business to locate or
relocate in Black Hills Power's service territory. Black Hills Power has
available resources to compete for new large load customers through this new
tariff.
Current Status of Competition for Service at Retail
- ---------------------------------------------------
In addition to Black Hills Power, RECs and the federal government through WAPA
provide electric service in and around the service territory of Black Hills
Power. Black Hills Power's transmission system is interconnected to Pacific
Power's transmission system near Gillette, Wyoming, and to WAPA's system near
Scottsbluff, Nebraska. Pacific Power provides electric service at retail to
large portions of Wyoming. Black Hills Power and the RECs serve in territories
which are protected by state laws or regulations which generally give each
entity the exclusive right to serve retail customers in its respective
territory; however, these laws or regulations are subject to change and there
are certain exceptions. In South Dakota, the SDPUC may allow a new customer with
a load of over 2,000 kilowatts to choose to be served by a utility other than
the utility in whose territory the new customer locates. In Wyoming, public
utilities operate in service territories assigned by the WPSC, and a franchise
granted by the municipality's governing body is required to serve within a
municipality. Black Hills Power may apply for and obtain the right to serve in
another utility's electric service territory if it is found to be in the public
interest to do so, but such applications are rarely granted.
The respective service territories of Black Hills Power and the RECs were
originally assigned based on where each was serving at the time of assignment.
Since the RECs were serving in rural areas (the purpose for which they were
formed), a large portion of the rural area surrounding the municipalities in
which Black Hills Power serves constitutes REC service territory. Although Black
Hills Power has traditionally served considerable territory outside of
municipalities and, therefore, has been assigned a large amount of such
territory, the RECs have the largest portion of such area and, if the laws are
not changed, will over a long period of time tend to receive a larger portion of
the growth of the population centers.
Every municipality in Black Hills Power's service territory has the right, upon
meeting certain conditions, to acquire or construct a municipally owned electric
system and to serve customers within its city. As a wholesaler of electric power
and energy, such municipality would have the power to demand and receive
transmission access over Black Hills Power's transmission system consistent with
its open access transmission tariff. The FERC has recognized the principle that
a city, which establishes a municipal electric system and buys power from a
supplier other than its former electric utility, should compensate the former
supplier for any stranded costs caused by the change in the power supplier.
However, the Company can give no assurances to what extent the stranded cost
provisions will be administered or how they would be applied to Black Hills
Power. Black Hills Power is not aware of any movement by any municipality in its
service territory which does not already have a municipally owned electric
system to establish one.
The primary competing fuel in Black Hills Power's territory is natural gas which
is available to approximately 80 percent of its customers.
Competition in Electric Generation
- ----------------------------------
The business of electric generation is no longer reserved exclusively for the
traditional public utility such as Black Hills Power. The Energy Policy Act of
1992 exempted independent power producers engaged exclusively in the sale of
power at wholesale from the onerous restrictions of the Public Utility Holding
Company Act. The Public Utility Regulatory Policies Act of 1978 (PURPA)
authorizes entities generating electricity from waste fuel and renewable fuel or
utilizing steam for both generation and other purposes to force a public utility
to purchase the energy at an avoided cost. These laws, together with the FERC
mandating all public utilities under its jurisdiction to file tariffs providing
transmission access for sales of energy at wholesale, have caused electric
generation and the marketing of electric energy at wholesale to become extremely
competitive. While independent power producers, other than qualifying facilities
under PURPA, are regulated by the FERC, the FERC is allowing rates for the sale
of generation to be determined by the market rather than by costs if the
producer or marketer can demonstrate no market power.
As a result of these changes in the law and regulations, the traditional public
utility, such as Black Hills Power, is more likely to purchase energy required
for its franchised service territories through competitive bidding and either
not expand its rate base generating capabilities or engage in the electric
generation business through independent power producers by selling to other
utilities. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS -RESULTS OF OPERATIONS - Independent Power
Production.)
Future generation, whether constructed by a public utility or an independent
power producer, is likely to be justified strictly on the basis of the
marketability of the capacity and energy from the new source in a competitive
market.
Black Hills Power could face the competition of industrial and public customers
constructing self-generation facilities using alternative fuels, such as waste
material, natural gas or oil. To date, Black Hills Power has not faced any
material competition from such sources and management does not believe that such
sources are cost effective and the company believes its rate design allows
flexibility in rates should competition become a threat, but no assurances can
be given that material competition from these sources will not occur.
This waiver will remain in effect until such time that Black Hills Power is
determined (by FERC) to not be providing information about its transmission
network to other potential system users.
Transmission Access
- -------------------
In 1996, the FERC adopted Order 888 that requires each public utility under its
jurisdiction to file open access transmission tariffs that provide rates which
are comparable to the same transmission costs of the public utility to transmit
power over its system. The rates provide for various transmission services to be
provided for any competitor but apply to the transmission of electric power for
wholesale purposes only. FERC has established Black Hills Power's open access
transmission tariffs. The regulations further require the public utility to keep
posted for public access, on an electronic bulletin board, all current
information concerning the availability and rates for these transmission
services. In 1996, Black Hills Power was granted an extension by FERC to delay
establishing an electronic bulletin board until WAPA, which operates the control
area in which Black Hills Power is located, establishes or participates in an
electronic bulletin board. In June, 1999, Black Hills Power obtained a full
waiver (from FERC) from meeting these electronic bulletin board reporting
requirements. The public utilities are further required by FERC to adopt
standards of conduct which require the functional separation of those persons
who operate and market the transmission system from those persons who buy and
sell power for the same utility; however, the FERC granted a waiver to Black
Hills Power from the requirement to adopt the standards of conduct in view of
Black Hills Power's small transmission system and lack of significant market
control. The regulations are designed to attempt to eliminate any market
advantage of the utility owning transmission over others engaged in the sale of
electric power at wholesale.
The new FERC regulations requiring the filing of open access tariffs does not
apply to the nonjurisdictional utilities such as the RECs and publicly owned
electric utilities. However, these nonjurisdictional utilities are subject to
the law that allows the FERC to force them to provide transmission services upon
application, and the FERC has adopted reciprocity regulations that would
authorize a jurisdictional utility to deny transmission access to a
nonjurisdictional utility which has denied access.
Black Hills Power currently furnishes transmission service for competing RECs
through contract. As long as the states in which Black Hills Power operates
continue to grant exclusive service territories, the federal government does not
preempt this state jurisdiction and municipalities in Black Hills Power's
service territory do not establish municipal electric systems, the increase in
transmission access for wholesale purposes through Black Hills Power's
transmission system is not likely to have any material adverse effect upon Black
Hills Power. Such open access may have a beneficial effect by opening
opportunities for the Company to further the marketing of coal-fired energy
outside of its service territory. On December 20, 1999, the FERC issued Order
No. 2000, Final Rule on Regional Transmission Organizations ("RTOs"). The
objective of FERC is for all transmission-owning entities, including non-public
utility entities, to place their transmission facilities under the control of
appropriate RTOs in a timely manner. Black Hills Power is a FERC jurisdictional
utility and per Order 2000 will be required to make a filing with FERC by
October 15, 2000 which will either contain a proposal for establishing an
operational RTO by December 15, 2001, or a description of our efforts to
participate in an RTO, any existing obstacles in achieving RTO participation,
and any plans to work towards RTO participation. Black Hills Power has been
actively participating in various discussion groups in reviewing some of the
various aspects associated with participating and establishing this type of
organization for this region. Black Hills Power will be making a filing to the
FERC.
Retail Wheeling
- ---------------
Legislative proposals requiring a public utility to allow its competitors to
utilize the utility's electric distribution system to serve end-use customers
who are located in service areas assigned to that public utility, commonly
referred to as retail wheeling, are getting serious consideration in Congress
and has been adopted in numerous states and is being considered and studied in
many other states. Since the duplication of electric transmission and
distribution systems would neither be efficient nor tolerable by the public, the
transmission and distribution portion of the business is likely to continue to
be regulated with rates based on costs. The Company cannot predict when and if
mandated retail wheeling will come to the areas where it now provides exclusive
retail electric service. Major problems should be resolved first, such as the
preservation of reliable service, compensation to a utility for investment
incurred to fulfill its duty to serve but stranded because of competition,
fairness of market pricing between large industrial users and small business and
residential users and assurances that all utilities, including the RECs, are
bound to operate under the same rules.
The SDPUC and WPSC continue to monitor the potential impacts of electric utility
industry restructuring and retail competition in South Dakota and Wyoming. At
this time, South Dakota does not have any legislative activity regarding retail
wheeling. During the 1999 legislative session, the Wyoming State Senate rejected
a bill which would have required the WPSC to hold formal hearings and provide a
report regarding the effects of retail wheeling in Wyoming. Several credible
studies, including a study for the US Department of Energy, have indicated that
electric rates for residential customers in South Dakota and Wyoming may
increase if there is national retail competition. The Company is unable to
predict whether Congress or the states may in the future require electric retail
competition and, if they do, whether the ground rules for competition will be
fair to all participants including its related impacts on customers rates.
Management is unable to predict the effect of full electric retail competition
on the Company's earnings. Management does anticipate that a transition period
of at least five years will be required to achieve a fully competitive electric
energy retail market. During that five years, Black Hills Power will endeavor to
increase its earnings through additional sales and cost management. Based upon
the FERC's expressed positions concerning open access transmission regulations,
electric utilities which will lose revenues due to competition should be allowed
recovery of stranded costs. The market price of electric energy in a fully
competitive market is expected to be based upon a much wider geographical area
than just Black Hills Power's service territory. Because energy providers are
likely to seek the markets where the highest profit margins can be realized,
today's rates designed to serve exclusive service territories may be
substantially different for service to a fully competitive market.
However, the Company is unable to predict future markets and economic conditions
and government actions or inaction that could have a materially adverse affect
on Black Hills Power's ability to compete in a fully competitive electric power
market and to maintain its equity return on investment.
INDEPENDENT ENERGY
Coal Sales to Black Hills Power's Plants
- ----------------------------------------
Wyodak Resources sells coal to Black Hills Power for all of its requirements
under an agreement that limits earnings from all coal sales to Black Hills Power
(including the 20 percent share on the Wyodak Plant and all sales to Black Hills
Power's other plants) to a return on Wyodak Resources' original cost,
depreciated investment base. The return is 4 percent (400 basis points) above
A-rated utility bonds to be applied to Wyodak Resources' coal mining investment
base as determined each year. Black Hills Power made a commitment to the SDPUC,
the WPSC and the City of Gillette that coal would be furnished and priced as
provided by this agreement for the life of NS #2. Earnings from the intercompany
sales of coal at this time represent 4.5 percent of the Company's 1999
consolidated earnings.
Sales and production statistics for the last three calendar years comparing
sales to Black Hills Power to others are as follows:
% Revenue
Revenue Derived
from Sale from Black Tons of
Year of Coal Hills Power Coal Sold
- ---- --------- ----------- ---------
(in thousands, except % revenue)
1999 $31,095 25 3,180
1998 31,413 33 3,280
1997 31,080 36 3,251
Coal Sales to the Wyodak Plant
- ------------------------------
Wyodak Resources furnishes all of the fuel supply for the Wyodak Plant in which
Black Hills Power owns a 20 percent interest and Pacific Power an 80 percent
interest. (See Note 6 of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.) The price
for unprocessed coal sold to Pacific Power for its 80 percent interest in the
Wyodak Plant is determined by a coal supply agreement entered into by Black
Hills Power, Pacific Power and Wyodak Resources in 1978 and terminating in the
year 2013. This agreement was amended and restated in 1987. Revenue from coal
sales to the Wyodak Plant totaled $24,883,000 in 1999 or 80 percent of revenue
for all coal sold by Wyodak Resources. The quantity of coal sold in 1999 for the
Wyodak Plant was 2,078,000 tons, as compared to 2,120,000 tons sold in 1998.
Barring unusual periods of maintenance, the quantity of coal for the maximum
consumption capability of the Wyodak Plant for one year is approximately
2,100,000 tons and the average yearly consumption is 1,900,000 tons. The average
consumption is expected to continue during the remaining 14 years of the coal
agreement. However, from time to time, the plant's physical operating
capabilities will affect the quantity of coal burned.
Of the 3,180,000 tons of coal sold by Wyodak Resources in 1999, 1,398,000 tons
were sold to Black Hills Power, 1,663,000 tons were sold to Pacific Power and
119,000 tons were sold to others.
Wyodak Resources' revenue from sales of coal to Pacific Power and Black Hills
Power as compared to its revenue from all sales to total unaffiliated customers
for the last three years was as follows:
1999 1998 1997
---- ---- ----
(in thousands)
Sales to:
Pacific Power $22,610 $20,263 $19,240
Black Hills Power 7,664 10,256 11,089
All unaffiliated
customers 23,431 21,157 19,991
Oil and Gas Operations
- ----------------------
The Company's oil and gas production is sold at or near the wellhead, generally
at prevailing posted prices. Black Hills Exploration and Production has been
able to market all of its oil and gas production. Oil and natural gas revenues
are subject to market price volatility.
Operating revenue by source for the last three years was as follows:
Oil and Gas Gas Plant Field
Year Sales Revenue Services
---- ----------- --------- --------
(in thousands)
1999 $10,075 $738 $2,239
1998 9,204 613 2,745
1997 9,763 755 2,777
Black Hills Exploration and Production sold approximately 783,000 equivalent
barrels of oil in 1999 comprised of 59 percent gas and 41 percent oil.
Energy Marketing Operations
- ----------------------------
The Company's energy marketing operations market natural gas, crude oil, and/or
coal to customers in the East Coast, Midwest, Southwest, Rocky Mountain, West
Coast and Northwest regions of the United States. Natural gas marketing
operations are located in Denver, Colorado, with sales offices in Chicago,
Illinois and Calgary, Alberta, Canada. Crude oil marketing operations are
headquartered in Houston, Texas with sales offices in Tulsa, Oklahoma and
Midland, Texas. Coal marketing operations are headquartered in Mason, Ohio with
sales offices in Turnersville, New Jersey and St. Clairsville, Ohio.
In September 1999, the Company consolidated its wholesale gas marketing
operations into the Denver, Colorado office. In the fourth quarter of 1999, the
Company sold its retail gas marketing operations in Colorado and Pennsylvania.
In July 1999, Black Hills Energy Resources acquired a minority ownership
interest in a 200 mile pipeline with a capacity of 67,000 barrels per day. The
majority owner and operator of the pipeline is Equilon Pipeline Company.
In October 1998, Enserco Energy, Inc. reacquired the other shareholder
interests becoming a wholly-owned subsidiary of Black Hills Capital Group. In
September 1998, Black Hills Capital Group formed Black Hills Coal Network which
acquired the assets and hired the operational management of Coal Network, Inc.
and Coal Niche, Inc. based in Mason, Ohio.
In July 1997, Black Hills Capital Group acquired, through Wickford Energy
Marketing, Inc., the assets and hired the operational management of Jomax
Partners, L.P. as successor and survivor of Wickford Energy Marketing, L.C. and
Wickford Energy Marketing Canada Company.
Revenues and marketed daily volumes by energy product for the last three years
are as follows:
1999 1998 1997
---- ---- ----
(in thousands)
Revenues:
Natural gas $382,809 $375,934 $95,980*
Crude oil 192,207 117,185 46,810*
Coal 39,212 12,924* -
Daily Volumes:
Natural gas
(mmbtus) 486,800 487,000 231,000*
Crude oil
(barrels) 19,270 19,000 12,600*
Coal (tons) 4,500 4,400* -
*Since date of acquisition
The marketing operations are high volume, low margin businesses whose
contribution to consolidated earnings has not been significant.
Independent Power Production
- ----------------------------
In December 1999, Black Hills Generation and Indeck Capital, Inc. jointly
acquired 111 megawatts of natural gas-fired combustion turbines under
construction in Colorado. The project has a seven year tolling agreement with
Public Service Company of Colorado and is expected to cost approximately $80
million. In-service date for the project is expected to be June of 2000.
In August 1999, Black Hills Generation began initial engineering and site
preparation for an 80 megawatt coal-fired electric generation facility at the
Wyodak coal mine.
In January 2000, the Company announced a definitive agreement, subject to
certain conditions of closing including regulatory approval, to acquire Indeck
Capital, Inc., a privately held independent power producer.
COMMUNICATIONS OPERATIONS
In September 1998, Black Hills Capital Group formed Black Hills Fiber Systems,
Inc. (formerly Black Hills FiberCom, Inc.). Black Hills Fiber Systems, Inc. owns
a 51 percent equity interest in Black Hills FiberCom, LLC which provides
facilities-based communication services for Rapid City and the Northern Black
Hills of South Dakota. The Company partnered with an international
telecommunications firm, GLA International, of St. Louis, Missouri, to build
Black Hills FiberCom's 200 mile fiber optic backbone and a 500-mile hybrid fiber
coaxial (HFC) network in Rapid City and the Northern Black Hills.
In the fourth quarter of 1999, the company began providing state-of-the-art
technology offering local and long distance telephone service, expanded cable
television service, Internet access, and high-speed data and video services to
residential and business customers.
The hybrid fiber coaxial cable link enables customers to receive telephone,
cable television, internet, and high-speed data and video services all through
one cable coming into their businesses and homes. The network is designed to
provide greater reliability because there is redundancy built into the system.
Compared with the present telecommunications network in the Black Hills,
connections to homes and businesses will have significantly greater capacity.
At December 31, 1999 the Company had built 200 miles of fiber optic backbone and
100 miles of HFC plant and was serving business and residential customers.
DAKSOFT, Inc. develops and markets internally generated computer software
associated with the Company's business segments and the utility and
communications industries.
ENVIRONMENTAL REGULATION
The Company is subject to extensive federal, state and local laws and
regulations governing discharges to the air and water, as well as the handling
and disposal of solid and hazardous wastes, including without limitation the
federal Clean Air Act (as amended in 1990), the federal Water Pollution Control
Act ("Clean Water Act"), the federal Toxic Substances Control Act and various
state laws, including solid waste disposal laws (collectively "Environmental
Regulatory Laws"). Governmental authorities have the power to enforce compliance
with Environmental Regulatory Laws, and violators may be subject to civil or
criminal penalties, injunctions or both. Third parties also may have the right
to sue to enforce compliance.
Air Quality
- -----------
Under the federal Clean Air Act, the federal Environmental Protection Agency
("EPA") has promulgated national air quality standards for certain air
pollutants, including sulfur oxides, particulate matter and nitrogen oxides. The
Company was granted a prevention of significant deterioration ("PSD")
construction permit by the DEQ for NS #2. The PSD construction permit set
emission rate limitations on particulate, sulfur dioxide, nitrogen oxides and
opacity. Black Hills Power has been in substantial compliance with its PSD
construction permit in its operations of NS #2 since its completion in August of
1995. Black Hills Power received an operational PSD construction permit from DEQ
in 1999.
Amendments to the Clean Air Act in 1990 will require a significant reduction in
nationwide sulfur oxide emissions by fossil fuel-fired generating units to a
permanent total emissions cap in the year 2000. This reduction is to be achieved
by the allotment of allowances to emit sulfur dioxide measured in tons per year
to each owner of a unit and requiring the owner to hold sufficient allowances
each year to cover the emissions of sulfur oxide from the unit during that year.
Black Hills Power holds sufficient allowances credited to it as a result of
sulfur removal equipment previously installed on the Wyodak Plant to apply to
the operation of NS #2 and its interest in the Wyodak Plant in the year 2000
without requiring the purchase of any additional allowances. Current law does
not require allowances for Black Hills Power's other plants.
All existing generating units of the Company are required to obtain operating
source permits under the Clean Air Act amendments. The operating permit
applications for the Osage and NS #1 generating units were submitted in 1995 and
received in 1997. Air quality permits for the Ben French Station were renewed in
1999 by the Department of Environment and Natural Resources of South Dakota.
Because the 1990 amendments to the Clean Air Act have been or will be
implemented and interpreted in the future, compliance with yet-to-be promulgated
and interpreted regulations may require additional capital and operational
expenditures in the future, most likely from enhanced monitoring costs. Due to
the political sensitivity and volatility of environmental issues and how they
may be implemented, management can give no assurances that unexpected additional
capital and operating costs may be required in the future that would have a
material impact on financial results.
Water Quality
- -------------
The federal Clean Water Act requires permits for discharges of effluent and that
all discharges of pollutants comply with federally approved state water quality
standards. Black Hills Power currently has in place all required permits under
the Clean Water Act for discharges from all of the power plants in which Black
Hills Power has an interest. While management believes that it is in full
compliance with all federal and state clean water laws and regulations, for all
the same reasons as stated in the previous paragraph, no assurances can be given
of the extent of costs to comply with clean water requirements in the future.
Land Quality - Solid Waste Disposal
- -----------------------------------
Black Hills Power disposes all solid wastes collected as a result of burning
coal at its power plants in approved solid waste disposal sites. Each disposal
site has been permitted by the state of its location in compliance with law. Ash
and wastes from flue gas and sulfur removal from the Wyodak Plant and NS #2 are
deposited in Wyodak Resources' mined areas. These disposal areas are located
below some shallow water aquifers in the mine. None of the solid wastes from the
burning of coal is classified as hazardous material, but the wastes do contain
minute traces of metals that would be perceived as polluting if such metals were
leached into underground water. Recent investigations have concluded that the
wastes are relatively insoluble and will not measurably affect the post-mining
ground water quality. While management does not believe that any substances from
the solid waste disposal will pollute underground water, they can give no
assurances that over a long period of time such could never happen. In such
event, the Company could experience material costs in mitigating any damages
from such pollution. Agreements in place require Pacific Power to be responsible
for any such costs that would be related to the solid waste from its 80 percent
interest in the Wyodak Plant.
Additional unexpected material costs could also result in the future from either
the federal or state government determining that solid waste from the burning of
coal does contain some hazardous material that requires some special treatment,
including solid waste previously disposed of, and holding those entities who
disposed of such waste responsible for such treatment. Such unexpected
governmental requirements are beyond the control of the Company.
Reclamation
- -----------
Under federal and state laws and regulations, Wyodak Resources is required to
submit to and receive approval from the DEQ for a mining and reclamation plan
which provides for orderly mining, reclaiming and restoring of all land in
conformity with all laws and regulations. Wyodak Resources has an approved
mining permit and is otherwise in compliance with other land quality permitting
programs.
One condition that could result in substantial unexpected increases in costs of
the reclamation permit relates to three depressions, the existing south
depression, the Peerless depression and the North Pit depression, which have or
will result from Wyodak Resources' mining. Because of the thick coal seam and
relatively shallow overburden, the present plan for restoration leaves areas of
the mine that will have limited reclamation potential because of their location
in depressions with interior drainage only. While the DEQ has allowed these
depressions in the present plan, the DEQ has reserved the right to review and
evaluate future mining plans proposed by Wyodak Resources. Such plans are
reviewed for the feasibility and desirability of causing Wyodak Resources to
place additional overburden generated elsewhere for the purpose of reducing the
depressions if the DEQ finds that the placement is necessary to prevent
degradation of more areas than expected. The DEQ has allowed the depressions at
the maximum acres specified and subject to maintenance of water quality at the
sites. Exceedence of acreage limitations or degradation of water quality could
result in material additional requirements placed upon Wyodak Resources,
including the placement of additional quantities of overburden in the
depressions and restoring water quality. Based on extensive reclamation studies,
accruals are maintained to comply with all reclamation requirements. However, no
assurances can be given that additional requirements in the future may be
imposed that cause unexpected material increases in reclamation costs.
Ben French Oil Spill
- --------------------
In 1990 and 1991, Black Hills Power discovered extensive underground fuel oil
contamination at the Ben French Plant site. With the help of expert consultants,
the Company engaged in assessment and remediation and has worked closely with
the South Dakota Department of Environment and Natural Resources. Assessment and
remediation efforts are continuing up to the present time. All underground
oil-carrying facilities from which the contamination occurred are now above
ground. There have been no significant recoveries of free fuel oil product since
1994. Black Hills Power continues to monitor the site. Soil borings and
monitoring wells on the perimeters of Black Hills Power's Ben French Plant
property are showing no indication of contamination beyond the property's
limits. Management believes that the underground spill has been sufficiently
remedied so as to prevent any oil from migrating off site. However, due to
underground gypsum deposits in this area, the fuel oil has the potential of
migrating to area waterways. In such event, cleanup costs could be greatly
increased. Management believes that sufficient remediation efforts to prevent
such a migration are currently in place, but due to the uncertainties of
underground geology, no assurance can be given.
Cleanup costs recognized to date total approximately $465,000, of which amount
$379,000 has been reimbursed from the South Dakota Petroleum Release
Compensation Fund. To date, no penalties, claims or actions have been taken or
threatened against the Company because of this oil spill.
PCBs
- ----
Under the federal Toxic Substances Control Act, the EPA has issued regulations
that control the use and disposal of polychlorinated biphenyls (PCBs). PCBs had
been widely used as insulating fluids in many electric utility transformers and
capacitors manufactured before the Toxic Substances Control Act prohibited any
further manufacture of such PCB equipment. Black Hills Power removes and
disposes of PCB-contaminated equipment in compliance with law as it is
discovered.
Several years ago, Black Hills Power began a testing program of possible
PCB-contaminated transformers, and in 1997 completed testing of all transformers
and capacitators which are not located in Black Hills Power's electric
substations. Black Hills Power has not completed the testing of sealed potential
transformers and bushings located in its electric substations as the testing of
such equipment will require the destruction of the equipment. While release of
PCB-contaminated fluid, if present, from such equipment is unlikely and the
volume of fluid in such equipment is generally less than one gallon, any release
of such fluid would be confined to Black Hills Power's substation site.
Release of PCB-contaminated fluids, especially any involving a fire or a release
into a waterway, could result in substantial cleanup costs. As the result of the
September 18, 1996 inspection by the Environmental Protection Agency of Black
Hills Power's Deadwood Avenue facility located in Rapid City, South Dakota, the
United States Environmental Protection Agency Region VIII filed a complaint
dated September 30, 1998, alleging three counts of violations of PCB regulations
and proposing a civil penalty of $13,600. Black Hills Power filed an answer
contesting the complaint. Based on Black Hills' answer and subsequent facts and
information, the EPA withdrew their complaint and an order was entered by an
administrative law judge dismissing the complaint on December 1, 1998.
Electromagnetic Fields
- ----------------------
A number of studies have examined the possibility of adverse health effects such
as cancer from electromagnetic fields (EMF) which are caused by electric
transmission and distribution facilities, however, recent studies have shown no
adverse effects. Certain states have enacted regulations to limit the strength
of magnetic fields at the edge of transmission line rights-of-way. None of the
jurisdictions in which Black Hills Power operates has adopted formal rules or
programs with respect to EMF or EMF considerations in the siting of electric
facilities. Black Hills Power expects that public concerns will make it more
difficult and costly to site and construct new power lines and substations in
the future. It is uncertain whether Black Hills Power's operations may be
adversely affected in other ways as a result of EMF concerns. Black Hills Power
is designing all new transmission lines under EMF standards adopted by the State
of Florida so as to minimize the EMF effect. The Company is unable to predict
the future costs to the electric utility industry, including the Company, if a
determination is made in the future, either based on facts or perception, that
EMF causes adverse health effects.
The Company makes ongoing efforts to comply with new as well as existing
environmental laws and regulations to which it is subject. It is unable to
estimate the ultimate effect of existing and future environmental requirements
upon its operations.
EMPLOYEES
At December 31, 1999, the number of employees of the Company (including Black
Hills Power), independent energy companies and communications companies, were
300, 105 and 70, respectively, for a total of 475 employees.
Approximately 48 percent of the employees of Black Hills Power are covered by
union contracts with the International Brotherhood of Electrical Workers. In the
Company's opinion employee relations are satisfactory.
- --------------------------------------------------------------------------------
ITEM 2. PROPERTIES
ELECTRIC PROPERTIES
The following table provides information on the generating plants of Black Hills
Power. During 1999, 99 percent of the fuel used in electric generation, measured
in Btus (British thermal units), was coal.
Generating Units
- ----------------
Name Plate
Year of Rating Principal
Installation (Kilowatts) Fuel
------------ ----------- ---------
Osage Plant - Osage, Wyoming 1948-1952 34,500 Coal
Ben French Station-Rapid City,
South Dakota 1960 25,000 Coal
1965 10,000 Oil
1977-1979(a) 100,000 Oil or gas
Neil Simpson Station-Gillette,
Wyoming 1969 21,760 Coal
1995(b) 88,900 Coal
Wyodak Plant - Gillette, Wyoming 1978(c) 72,400 Coal
-------
Total 352,560
=======
(a) These combustion turbines are those referenced by ITEM 1. BUSINESS -
ELECTRIC POWER SUPPLY - Pacific Power's Reserve Capacity Integration
Agreement.
(b) NS #2 was placed into commercial operation in August 1995. The plant's
total production may, at times, exceed its name plate rating by 11 MWs.
(c) Black Hills Power's 20 percent interest. See Note 6 of "NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS".
Black Hills Power owns transmission lines and distribution systems in and
adjoining the communities served consisting of 447 miles of 230 kV, 530 miles of
69 kV, 8 miles of 47 kV and numerous distribution lines of less voltage. Black
Hills Power owns a service center in Rapid City, several district office
buildings at various locations within its service area and an eight-story home
office building at Rapid City, South Dakota, housing its home office on four
floors, with the balance of the building rented to others.
INDEPENDENT ENERGY PROPERTIES
Independent energy properties consist of coal mining properties, oil and natural
gas properties, energy marketing properties and independent power properties.
Coal Mining Properties
- ----------------------
Wyodak Resources is engaged in mining and processing sub-bituminous coal near
Gillette in Campbell County, Wyoming, and owns or has user rights in the
necessary mining, processing and delivery equipment to fulfill its sales
contracts. The coal averages 8,000 Btus per pound. Mining rights to the coal are
based upon four federal leases and one state lease. The estimated recoverable
coal from the leases as of December 31, 1999 is 277,717,000 tons, of which
19,934,000 tons are committed to be sold to the Wyodak Plant and approximately
24,150,000 tons to Black Hills Power's other plants.
Each federal lease grants Wyodak Resources the right to mine all of the coal in
the land described therein, but the government has the right at the end of 20
years from the date of the lease to readjust royalty payments and other terms
and conditions. All of the federal leases provide for a royalty of 12.5 percent
of the selling price of the coal. The state lease provides for a royalty to be
determined every five years. Currently, the royalty on the state lease, approved
in 1998, is 9 percent of the selling price of the coal. Each federal lease and
state lease requires diligent development to produce at least one percent of all
recoverable reserves within either 10 years from the respective dates of the
1983 leases or 10 years from the date of adjustment of the other leases. Each
lease further requires a continuing obligation to mine, thereafter, at an
average annual rate of at least one percent of the recoverable reserves. All of
the federal leases and the state lease constitute one logical mining unit which
is treated as one lease for the purpose of determining diligent development and
continuing operation requirements. All coal is to be mined within 40 years from
December 31, 1991, the date of the logical mining unit. Even if federal and
state coal leases are not mined out in 40 years, the Company believes that the
federal coal is likely to be available for further lease after the 40 years.
Wyodak Resources' current coal agreements require production which should be
sufficient to satisfy the diligent development and continual operation
requirements of present law absent any unexpected event. Wyodak Resources will
require additional coal sales in order to mine all of its state and federal coal
within the 40 year requirement.
The law, which requires that an owner of land that is primarily devoted to
agriculture must approve a reclamation plan before the state will approve a
permit for open pit mining, affects approximately 3,100,000 tons of the
recoverable coal. Wyodak Resources has excluded these tons of coal from its mine
plan and will not mine such coal until a surface consent has been negotiated or
the right to mine has been settled by litigation.
Oil and Natural Gas Properties
- ------------------------------
Black Hills Exploration and Production operates 298 wells as of December 31,
1999. The majority of these wells are in the Finn Shurley Field, located in
Weston and Niobrara Counties, Wyoming. Black Hills Exploration and Production
does not operate, but owns a working interest in 284 producing properties
located in the western and southern United States. Black Hills Exploration and
Production also owns a 44.7 percent non-operating interest in a natural gas
processing plant also located at the Finn Shurley Field.
Black Hills Exploration and Production participated in the drilling of 52
exploratory and development wells in 1999. Black Hills Exploration and
Production's average working interest in such wells was 17 percent, or 9 net
wells. A development well is a well drilled within the presently proved
productive area of an oil and gas reservoir, as indicated by reasonable
interpretation of available data, with the objective of completing in that
reservoir. An exploratory well is a well drilled in search of a new, as yet
undiscovered oil or gas reservoir or to greatly extend the known limits of a
previously discovered reservoir. Thirty-nine out of the 52 wells drilled in 1999
were completed as producing wells for an overall drilling success rate of 75
percent.
See the table in Note 10 of "NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS" for
Black Hills Exploration and Production's estimated quantities of proved
developed and undeveloped oil and natural gas reserves at December 31, 1999,
1998 and 1997, and a reconciliation of the changes between these dates using
constant product prices for the respective years.
Energy Marketing Properties
- ---------------------------
In 1999, Black Hills Energy Resources formed Black Hills Millenium Pipeline
Company to own a minority interest in a 200 mile pipeline in Texas. The pipeline
has a capacity of 67,000 barrels per day. The majority owner and operator of the
pipeline is Equilon Pipeline Company LLC. The pipeline is scheduled to begin
operations in the second quarter of 2000.
Independent Power Properties
- ----------------------------
In December 1999, Black Hills Generation jointly acquired 111 megawatts of
natural gas-fired combustion turbines under construction in Colorado. Black
Hills Generation has a fifty percent interest (with Indeck Capital, Inc. owning
the other fifty percent). The turbines are expected to be placed in service in
June 2000.
COMMUNICATIONS PROPERTIES
Black Hills FiberCom, LLC is a competitive local exchange carrier providing
local and long-distance telephone service, cable television and high speed data
services. At December 31, 1999 the company has 200 miles of fiber optic backbone
cable and 100 miles of hybrid fiber coaxial cable to service its customers. When
deployment is complete the company expects to have approximately 500 miles of
hybrid fiber coaxial cable. In addition, the company owns a building housing its
employees, a central office switch and a cable head-end. The company also has
co-location rights within a US West Communications building.
ITEM 3. LEGAL PROCEEDINGS
Other Legal Proceedings
- ------------------------
The Company and its subsidiaries are involved in minor routine administrative
proceedings and litigation incidental to the businesses, none of which, in the
opinion of management, are expected to have a material effect on the
consolidated financial statements of the Company. .
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth quarter
of 1999.
PART II
ITEM 5. MARKET FOR REGISTRANT'S
COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The Company's Common Stock ($1 par value) is traded on The New York Stock
Exchange. Quotations for the Common Stock are reported under the symbol BKH. At
year-end, the Company had 6,086 common shareholders of record. All 50 states and
the District of Columbia plus 10 foreign countries are represented.
The Company has declared Common Stock dividends payable in cash in each year
since its incorporation in 1941. At its January 2000 meeting, the Board of
Directors raised the quarterly dividend to 27.0 cents per share, equivalent to
an annual increase of 4.0 cents per share. This regular quarterly dividend is
payable March 1, 2000. Dividend payment dates are normally March 1, June 1,
September 1, and December 1.
Quarterly dividends paid and the high and low Common Stock prices for the last
two years reflecting the 3-for-2 Common Stock split in March 1998 were as
follows:
Year ended December 31, 1999
1st 2nd 3rd 4th
--- --- --- ---
Dividends paid
per share $0.26 $0.26 $0.26 $0.26
Common stock
Prices
High $26.50 $23.88 $25.63 $23.31
Low $21.00 $21.00 $22.19 $20.31
Year ended December 31, 1998
1st 2nd 3rd 4th
--- --- --- ---
Dividends paid
per share $0.25 $0.25 $0.25 $0.25
Common stock
Prices
High $25.56 $24.25 $26.88 $27.94
Low $21.00 $20.69 $22.31 $24.13
- --------------------------------------------------------------------------------
ITEM 6. SELECTED FINANCIAL DATA
The following data was derived from the Company's audited financial statements.
Years ended December 31 1999 1998 1997 1996 1995
---- ---- ---- ---- ----
(in thousands, except per share amounts)
Operating revenues $791,875 $679,254 $313,662 $162,588 $149,817
Net income 37,067 25,808* 32,359 30,252 25,590
Per share of common stock:
Earnings - basic and diluted 1.73 1.19* 1.49 1.40 1.19
Dividends paid 1.04 1.00 0.95 0.92 0.89
Total assets 674,806 559,417 508,741 467,354 448,830
Long-term debt 160,700 162,030 163,360 164,691 166,069
Quarterly financial data for the years indicated (are summarized in thousands,
except per share amounts) as follows:
1st 2nd 3rd 4th
--- --- --- ---
Year ended December 31, 1999
Operating revenues $168,201 $186,195 $219,779 $217,700
Operating income 15,980 13,786 16,675 15,450
Net income 9,035 7,763 9,725 10,544
Earnings per share .42 .36 .45 .50
Year Ended December 31, 1998
Operating revenues $153,837 $161,334 $170,158 $193,925
Operating income 14,875 13,915 17,603 2,840*
Net income 8,544 7,497 9,616 151*
Earnings per share .39 .35 .45 .01*
*Includes $8.8 million, or 41 cents per share, non-cash writedown of certain
oil and gas properties.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
In light of the Company's expansion over the past two years into the areas of
communications and independent energy, during the fourth quarter of 1999, the
Company formally reorganized its operations into three distinct business units,
as follows:
o The electric utility business unit, consisting of Black Hills Power and
Light Company. This business unit supplies electric utility service in
western South Dakota, northeastern Wyoming, and southeastern Montana.
o The independent energy business unit, consisting of Wyodak Resources
Development Corp., Black Hills Exploration and Production, Inc., Enserco
Energy, Inc., Black Hills Energy Resources, Inc., Black Hills Coal Network,
Inc., Black Hills Energy Capital, Inc. and Black Hills Generation, Inc.
This business unit engages in the production and marketing of coal, crude
oil and natural gas. Beginning in 2000, this business unit is expected to
expand into the production and marketing of electricity through its pending
acquisition of Indeck Capital, Inc. and the development and acquisition of
other independent power interests.
o The communications business unit, consisting of a majority ownership of
Black Hills FiberCom, L.L.C. Black Hills FiberCom markets communications
services in Rapid City and the Northern Black Hills of South Dakota. This
business unit also includes DAKSOFT, Inc., which primarily develops and
markets internally generated computer software programs and services for
the utility and communications industries.
LIQUIDITY AND CAPITAL RESOURCES
In 1999, the Company generated cash from operations sufficient to meet its
operating needs, pay dividends on common stock, pay long-term debt maturities
and provide financing for the investment in independent power assets. Property
additions were primarily financed through increased short-term debt and notes
payable. In 1998 and 1997, the Company generated sufficient operating cash to
meet its operating needs, pay dividends and finance its capital requirements.
The 1999 property additions consisted of 1) the electric utility business unit's
construction of a 40 megawatt gas-fired combustion turbine, modernization of
facilities and replacement of equipment; 2) the independent energy business
unit's oil and natural gas drilling program, reserve acquisitions, replacement
and/or refurbishment of mining equipment and investment in a joint venture
pipeline; and 3) the communications business unit's additions primarily
represent the deployment of the state-of-the-art fiber optic communications
network in Rapid City and the northern Black Hills of South Dakota. The primary
capital requirements of the Company for the past three years were as follows:
1999 1998 1997
---- ---- ----
(in thousands)
Property additions:
Electric utility $31,911 $11,451 $12,484
Independent energy 21,337 12,040 8,412
Communications and other 50,977 1,774 191
Independent power investments 52,319 - -
Common stock dividends 22,602 21,737 20,540
Energy marketing assets - 1,960 7,232
Maturities/redemptions of long-term debt 1,330 1,331 1,534
--------- --------- ---------
$180,476 $50,293 $50,393
======== ======= =======
Capital requirements for projected construction, capital improvements,
independent energy investments, communications network construction and
corporate development activities for the next three years are estimated
(excluding any impact of future capital projects resulting from the pending
Indeck Capital, Inc. acquisition) to be as follows:
2000 2001 2002
---- ---- ----
(in thousands)
Electric utility $ 27,696 $13,490 $ 13,338
Independent energy 82,457 10,171 14,336
Communications 19,441 4,519 4,795
Corporate development 10,000 10,000 10,000
-------- -------- --------
$139,594 $38,180 $42,469
======== ======= =======
- -------------------------------------------------------------------------------
The electric utility's forecasted capital requirements include completion of the
construction of the 40 megawatt gas-fired combustion turbine, replacement of
equipment and modernization of facilities.
Independent energy's forecasted capital requirements include the pending $40
million acquisition of Indeck Capital, Inc., additional investment in the 111 MW
independent power project in Colorado, oil and natural gas drilling program and
reserve acquisitions and replacement of mining equipment and modernization of
facilities. In addition to the above noted independent energy business unit
capital requirements, the pending acquisition of Indeck Capital is expected to
provide growth opportunities in independent power production assets currently
estimated to be in the $25 million to $50 million range annually and the
proposed construction of an 80 MW coal-fired electric generating facility at the
Company's coal mine (WYGEN). Such projects will be evaluated based on the
economics of each project and are expected to be funded through the appropriate
mix of construction financing, long-term and short-term debt financing and
equity financing.
The communications business unit forecast primarily represents the completion of
the initial fiber optic network build-out in Rapid City and the northern Black
Hills in 2000 and extension of the system thereafter. Excluded from the forecast
are any additional market build-outs which will be evaluated at that time and
are expected to be funded with the appropriate mix of short-term debt, vendor
financing, long-term debt and equity.
Forecasted investment in corporate development activities is dependent on market
conditions at the time and the Company's ability to identify opportunities
consistent with its corporate strategy.
At December 31, 1999, electric operations is the only segment of the Company's
business with long-term debt. Long-term debt sinking fund requirements are: $1.3
million in 2000, $3.0 million in 2001 and $18.0 million in 2002.
Under its mining permit, Wyodak Resources is required to reclaim all land where
it has mined coal reserves. The cost of reclaiming the land is accrued as the
coal is mined. While the reclamation process takes place on a continual basis,
much of the reclamation occurs over an extended period after the area is mined.
Approximately $0.7 million is charged to operations as reclamation expense
annually. As of December 31, 1999, accrued reclamation costs were approximately
$17.3 million.
The Company has a Dividend Reinvestment and Stock Purchase Plan, under which
shareholders may purchase additional shares of Common Stock through dividend
reinvestment or optional cash payments at 100 percent of the recent average
market price. The Company has the option of issuing new shares or purchasing the
shares on the open market. The Company used the open market purchase option for
all of 1999, 1998 and 1997.
The debt component of the Company's capital structure at December 31, 1999 and
1998 was 43 percent and 44 percent, respectively.
The Company plans to place long-term non-recourse project level financing in
2000 to fund independent energy's combustion turbines in Colorado. In addition,
upon satisfaction of the conditions of closing, including regulatory approval,
the Company will issue equity and preferred stock to acquire Indeck Capital,
Inc. The Company will issue $36 million of common stock and $4 million of
preferred stock to fund the acquisition.
With expected growth in the independent energy and communications business
units, the Company anticipates its long-term debt ratio will increase to 50-55
percent in the next five years. (See ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RESULTS OF
OPERATIONS-Independent Power Production; and BUSINESS OUTLOOK STATEMENTS.)
The Company had $115 million and $12 million of unsecured short-term lines of
credit at December 31, 1999 and 1998, respectively, which provide for interim
borrowings and the opportunity for timing of permanent financing. There was
$96.6 million outstanding under these lines of credit as of December 31, 1999.
There are no compensating balance requirements associated with these lines of
credit.
In addition to the above lines of credit, Black Hills Energy Resources has a $25
million uncommitted line of credit with a national bank to provide credit
support for purchases and sales of crude oil. The Company does not provide
credit support for this agreement. At December 31, 1999, there were outstanding
letters of credit totaling approximately $13 million, which reduced the
available credit to $12 million.
In addition to the above lines of credit, Wyodak Resources has guaranteed a $25
million line of credit for Enserco to use to guarantee letters of credit.
Enserco pays a 0.125 percent facility fee on this line of credit. At December
31, 1999, there were no balances outstanding on this line of credit. At December
31, 1999 Enserco Energy, Inc. had $19.9 million in outstanding letters of
credit.
In the past, the Company has relied upon internally generated funds, issuance of
short and long-term debt and sales of common stock to finance its activities.
The Company expects an appropriate mix of financing options will be used to
finance future activities.
Credit ratings for the Company's First Mortgage Bonds are at an A1 level at
Moody's Investors Service, Inc. and at an A+ at Standard & Poor's. These ratings
reflect the respective agencies' opinions of the credit quality of the Company's
first mortgage bonds.
MARKET RISK DISCLOSURES
Commodity Risk
- --------------
The Company is exposed to market risk stemming from changes in commodity prices.
These changes could cause fluctuations in the Company's earnings and cash flows.
In the normal course of business, the Company actively manages its exposure to
these market risks by entering into various hedging transactions, which are
authorized under its policies that place clear controls on these activities.
Hedging transactions involve the use of a variety of derivative financial
instruments.
The Company has adopted a Risk Management Policies and Procedures, approved by
the Board of Directors, and reviewed routinely by the Audit Committee of the
Board of Directors. The Risk Management Policies and Procedures include, but are
not limited to, risk tolerance levels relating to authorized derivative
financial instruments, position limits, authorization of transactions and credit
exposure.
Operating margins earned by wholesale gas and crude oil marketing are relatively
insensitive to commodity price fluctuations since most of the purchase and sales
contracts do not contain fixed-price provisions. Generally, prices contained in
these contracts are tied to a current spot or index price and, therefore, adjust
directionally with changes in overall market conditions. The Company generally
attempts to balance its fixed-price physical and financial purchase and sales
commitments in terms of contract volumes, and the timing of performance and
delivery obligations. However, the Company may, at times, have a bias in the
market, within established guidelines, resulting from management of its
portfolio. To the extent a net open position exists, fluctuating commodity
market prices can impact the Company's financial position or results of
operations, either favorably or unfavorably. The net open positions are actively
managed, and the impact of changing prices on the Company's financial condition
at a point in time is not necessarily indicative of the impact of price
movements throughout the year.
Trading Activities
- ------------------
The Company, through its independent energy business unit, utilizes derivatives
for its energy marketing services. These financial instruments include fixed
price swap agreements, variable price swap agreements, basis swap agreements,
exchange-traded energy futures contracts, and swaps and collars traded in the
over-the-counter financial markets.
The derivatives are not held for speculative purposes but rather serve to hedge
the Company's exposure related to commodity purchases or sale commitments. Under
Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and
Risk Management Activities" (EITF 98-10), these transactions qualify as trading
activities which must be accounted for at fair value. As such, realized and
unrealized gains (losses) are recorded as a component of income. Additionally,
because of the Company's back-to-back transaction strategy, gains or losses only
exist to the extent that the transactions are not effectively matched. Because
the Company does not speculate with "open" positions, substantially all of its
trading activities are back-to-back positions where a commitment to buy a
commodity is matched with a committed sale or a financial instrument. During
1999, gains or losses on trading activities were not significant. The quantities
and maximum terms of derivative financial instruments held for trading purposes
at December 31, 1999 and 1998 are as follows:
Max.
Volume Covered Term
December 31, 1999 (MMBtu's) (Years)
- ----------------- -------------- -------
Natural gas futures
contracts purchased 860,000 1
Natural gas basis swaps
purchased 17,741,500 4
Natural gas basis swaps sold 18,390,517 4
Natural gas fixed for
float swaps purchased 9,490,486 1
Natural gas fixed for
float swaps sold 10,994,521 1
Natural gas collar
transactions; puts
purchased, calls sold 408,500 1
Natural gas collar
transactions; calls
purchased, puts sold 318,500 1
Max.
Volume Covered Term
December 31, 1998 (MMBtu's) (Years)
- ----------------- -------------- -------
Natural gas futures
contracts purchased 1,470,000 2
Natural gas swap
contracts purchased 7,989,096 3
Natural gas swap
contracts sold 1,473,000 1
Non-trading Activities
- ----------------------
To reduce risk from fluctuations in the price of oil and natural gas, the
Company enters into futures and swap transactions. The transactions are used to
hedge price risk from sales of the Company's crude oil and natural gas
production. For such transactions, the Company utilizes hedge accounting. (See
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Note 1 - BUSINESS DESCRIPTION AND
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Price Risk Management.)
At December 31, 1999, the Company had fixed rate for floating rate price swaps
sold for 20,000 barrels per month for the year 2000 to hedge its crude oil price
risk, with a fair value of $(0.5) million at December 31, 1999. At December 31,
1998, the Company did not have material crude oil derivatives in its non-trading
activities. At December 31, 1997, the company had price collars and fixed rate
for floating rate price swaps to hedge crude oil price risk for 15,000 barrels
of oil per month, resulting in the recognition of $0.9 million of gains during
1998.
Credit Risk
- -----------
In addition to the risk associated with price movements, credit risk is also
inherent in the Company's risk management activities. Credit risk relates to the
risk of loss resulting from non performance of contractual obligations by a
counterparty. While the Company has not experienced significant losses due to
the credit risk associated with these arrangements, the Company has off-balance
sheet risk to the extent that the counterparties to these transactions may fail
to perform as required by the terms of each such contract.
Interest Rate Risk
- ------------------
The Company's exposure to market risk for changes in interest rates relates
primarily to the Company's short-term investments and long-term debt
obligations. As stated in its policy, the Company is adverse to principal loss
and ensures the safety and preservation of its investments by limiting default
risk, market risk, and reinvestment risk.
The Company mitigates default risk by investing in high credit quality
securities consisting primarily of tax-exempt Federal, state and local agency
obligations and by constantly monitoring the credit rating of any investment
issuer or guarantor and by limiting the amount of exposure to any one issuer.
The portfolio includes only securities with active secondary or resale markets
to ensure portfolio liquidity. All short-term investments mature, by policy, in
two years or less.
The effect of a 100 basis point (1 percent) increase in interest rates would not
have a material effect to the Company's results of operations or financial
condition, due to the short-term duration of the investment portfolio.
The Company has no cash flow exposure due to rate changes for long-term debt
obligations. The Company primarily enters into debt obligations to support
general corporate purposes including capital expenditures and working capital
needs.
- --------------------------------------------------------------------------------
The table below presents principal (or notional) amounts and related weighted
average interest rates by year of maturity for the Company's short-term
investments and long-term debt obligations, including current maturities (in
thousands).
2000 2001 2002 2003 2004 Thereafter Total
---- ---- ---- ---- ---- ---------- -----
Cash equivalents
Fixed rate $ 16,482 $ - $ - $ - $ - $ - $ 16,482
Average interest rate 5.60% - - - - - 5.60%
Available for sale securities
Fixed rate $ 6,556 $ 1,030 $ - $ - $ - $ - $ 7,586
Average interest rate 4.14% 4.39% - - - - 4.18%
Total investment securities $ 23,038 $ 1,030 $ - $ - $ - $ - $ 24,068
Average interest rate 5.19% 4.39% - - - - 5.15%
Long-term debt
Fixed rate $ 1,330 $ 3,029 $ 18,018 $ 3,068 $ 1,955 $ 134,630 $162,030
Average interest rate 9.11% 9.24% 6.96% 9.24% 9.37% 8.20% 8.12%
RATE REGULATION
Existing Rate Regulation
- -------------------------
As of January 1, 2000 the rate freeze period of the 1995 South Dakota and
Wyoming rate cases relating to the inclusion of NS#2 into rate base expired. In
June of 1999, the SDPUC approved a settlement between Black Hills Power and the
commission staff, which extended the rate freeze from January 1, 2000, for
another five years.
The South Dakota settlement provides that absent an extraordinary event occurs,
Black Hills Power may not file for any increase in its rates or invoke any fuel
and purchased power adjustment tariff to take effect during the freeze period
ending January 1, 2005. The specified extraordinary events are: new governmental
impositions increasing annual costs in South Dakota above $2.0 million, forced
outages of both the Wyodak Plant and NS #2 projected to continue at least 60
days, forced outages occurring to either plant which are continued for a period
of three months and is projected to last at least nine months, an increase in
the Consumers Price Index at a monthly rate for six months which would result in
a 10 percent or more annual inflation rate, the loss of a South Dakota customer
or revenue from an existing South Dakota customer that would result in a loss of
$2.0 million or more during any 12-month period, Black Hills Power's cost of
coal to its South Dakota customers increases and is projected to increase by
more than $2.0 million over the cost for the most recent calendar year, and
electric deregulation as a result of either federal or state mandate which
allows any customer of Black Hills Power to choose its provider of electricity
at any time during the freeze period.
During the freeze period, except as identified above, Black Hills Power is
undertaking the risks of machinery failure, load loss caused by either an
economic downturn or changes in regulation, increased costs under existing power
purchase contracts over which the Company has no control, government
interferences, acts of nature and other unexpected events that could cause
material losses of income or increases in costs of doing business. However, the
settlement anticipates that Black Hills Power will retain during that period of
time earnings realized from more efficient operations, sales from load growth,
and off-system sales of power and energy.
In 1998, Black Hills Power initiated an effort to enter into a new contract with
its largest industrial customers. This effort was expanded in 1999. The new
contracts contain "meet or release" provisions which grant Black Hills Power a
five-year right to continue to serve a customer in the event of deregulation.
Additionally, Black Hills Power, through a new General Service Large Optional
Combined Account Billing Tariff, has allowed general service customers to
aggregate their loads, which also includes a provision for a five-year right to
continue to serve such customer in the event of deregulation. Black Hills
Power's "meet or release" contracts now total more than 95 MW of large
commercial and industrial load. These contracts provide Black Hills Power the
assurance of a firm local market for its power resources, should deregulation
occur. These industrial and large commercial customers, together with the
wholesale power sale agreements with the City of Gillette and MDU, equal
approximately 40 percent of Black Hills Power's firm load.
Regulatory Accounting
- ---------------------
Black Hills Power follows Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation," and its
financial statements reflect the effects of the different ratemaking principles
followed by the various jurisdictions regulating Black Hills Power. As a result
of Black Hills Power's regulatory activity, a 50-year depreciable life for NS #2
is used for financial reporting purposes. If Black Hills Power were not
following SFAS 71, a 35 to 40 year life would probably be more appropriate which
would increase depreciation expense by approximately $0.6 million per year. If
rate recovery of generation-related costs becomes unlikely or uncertain, due to
competition or regulatory action, these accounting standards may no longer apply
to Black Hills Power's generation operations. In the event Black Hills Power
determines that it no longer meets the criteria for following SFAS 71, the
accounting impact to the Company would be an extraordinary noncash charge to
operations of an amount that could be material. Criteria that give rise to the
discontinuance of SFAS 71 include increasing competition that could restrict
Black Hills Power's ability to establish prices to recover specific costs and a
significant change in the manner in which rates are set by regulators from
cost-based regulation to another form of regulation. The Company periodically
reviews these criteria to ensure the continuing application of SFAS 71 is
appropriate.
RESULTS OF OPERATIONS
Consolidated Results
- --------------------
Company-wide revenues were $791.9 million, $679.3 million, and $313.7 million in
1999, 1998, and 1997, respectively, representing 17% and 117% increases in 1999
and 1998, respectively. These revenue increases resulted primarily from the
acquisitions and growth in the energy marketing segment of the independent
energy business unit.
The Company reported record earnings for 1999, due primarily to sales growth in
the electric utility business unit, improved results in the independent energy
business unit partially offset by expected start-up losses in the communications
business unit. Consolidated net income for 1999 was $37.1 million compared to
$25.8 million in 1998 and $32.4 million in 1997 or $1.73 per average common
share in 1999, compared to $1.19 and $1.49 per average common share in 1998 and
1997, respectively. This equates to a 17.1 percent, 12.5 percent and 15.8
percent return on year-end common equity in 1999, 1998 and 1997, respectively.
In 1998, the Company recorded an $8.8 million (net-of-tax) charge to earnings
related to a write down of certain oil and natural gas properties. Absent this
charge, the Company's earnings per average common share for 1998 would have been
$1.60, and a return on year-end common equity would have been 16.1 percent. The
write down was primarily due to historically low crude oil prices, lower natural
gas prices and decline in value of certain unevaluated properties. Absent other
factors impacting depletion expense, the Company expects to continue to realize
the benefit of reduced future depletion expense per unit of production because
of this write down.
Dividends paid on common stock totaled $1.04 per share in 1999. This reflected
increases approved by the Board of Directors from $1.00 per share in 1998 and
$0.95 per share in 1997. All dividends were paid out of current earnings. The
Company's dividend objective is to increase the dividend at or above the
electric utility average and maintain the Company's payout ratio in the low
60's. Management believes this objective is attainable through earnings growth.
The Company's three year dividend growth rate was 4.1 percent and the payout
ratio for 1999 was 60 percent.
In January 2000 the Board of Directors increased the quarterly dividend 3.8
percent to 27 cents per share. If this dividend is maintained during 2000, it
will be equivalent to $1.08 per share, an annual increase of 4 cents per share.
Revenue and net income (loss) provided by each business unit as a percentage of
the Company's total revenue and net income, were as follows:
1999 1998 1997
---- ---- ----
Revenue:
Electric utility 17% 19% 40%
Independent
energy 83 81 60
Communications - - -
---- ---- ----
100% 100% 100%
==== ==== ====
1999 1998 1997
---- ---- ----
Net Income (Loss):
Electric utility 74% 96% 68%
Independent
energy 31 5 33
Communications (5) (1) (1)
---- ---- ----
100% 100% 100%
==== ==== ====
The electric utility business unit has continued its stable growth both in terms
of revenue and earnings over the past two years. Management believes this trend
is stable and, absent system outages, will continue for the next several years
due to the five-year extension of the electric utility's rate freeze in 1999.
(See RATE REGULATION above.)
Management believes that opportunities exist to continue the improvement of
results from the existing operations of the independent energy business unit.
The coal mining and exploration and production segments of this business unit
have provided, and are expected to continue to provide, stable cash flow and
operating results. Management believes that the refocused energy marketing
segments of this business unit will become profitable in 2000. Management also
believes the Company's entry into the independent power generation business in
2000, through the pending acquisition of Indeck Capital, Inc. and the completion
of the construction of the 111 MW of gas-fired combustion turbines in Colorado
will have a positive impact on the independent energy business unit in terms of
future growth and earnings. (See BUSINESS OUTLOOK STATEMENTS SECTION OF
MANAGEMENT'S DISCUSSION AND ANALYSIS.)
While management expects continued losses in the near term from the
communications business unit as the development of the fiber optics
communications system in Rapid City and the Northern Black Hills progresses,
management believes the long-term strategy related to this business unit will
result in increasing earnings and cash flows. Growth opportunities also exist in
the deployment of this technology in other markets.
EBITDA represents the sum of earnings before interest, taxes, depreciation and
amortization.
EBITDA:
o is not intended to be a performance measure that should be regarded as an
alternative either to operating income or net income as an indicator of
operating performance or to cash flows as a measure of liquidity;
o is not intended to represent funds available for debt service, dividends,
reinvestment, or other discretionary uses; and
o should not be considered in isolation or as a substitute for measures of
performance prepared in accordance with generally accepted accounting
principles.
EBITDA is included because our management believes that EBITDA is a meaningful
measurement commonly used by the investment community. Our definition of EBITDA
may not be identical to similarly titled measures reported by other companies.
Electric Utility Business Unit
- ------------------------------
1999 1998 1997
(in thousands)
Revenue $133,222 $129,236 $126,497
Operating expenses
80,936 79,340 81,886
-------- -------- ---------
Operating income $ 52,286 $ 49,896 $ 44,611
======== ======== =========
Net income $ 27,286 $ 24,825 $ 22,106
======== ======== =========
EBITDA $ 68,299 $ 64,936 $ 59,544
======== ======== =========
Electric revenue increased 3.1 percent in 1999 compared to a 2.2 percent
increase in 1998. Firm kilowatthour sales decreased 0.1 percent in 1999 compared
to a 0.4 percent decrease in 1998. The increase in electric revenue in 1999 was
primarily due to stable firm sales combined with a 20 percent increase in
off-system sales. Degree days, a measure of weather trends, were 9 percent below
1998 and 13 percent below normal. The increase in electric revenue in 1998 was
primarily due to a 60 percent increase in non-firm sales and a 2 percent
increase in commercial sales partially offset by 4 percent decrease in
industrial sales primarily due to Homestake's restructuring. Firm kilowatthour
sales declined slightly due to Homestake but total kilowatthour sales increased
4 percent primarily due to a 33 percent increase in off-system sales. Degree
days were 2 percent below 1997 and 4 percent below normal.
Revenue per kilowatthour sold was 5.4 cents in 1999 and 1998 compared to 5.5
cents in 1997. The number of customers in the service area increased to 57,709
in 1999 from 56,856 in 1998 and 56,269 in 1997. The revenue per kilowatthour
sold in 1999 reflects the 20 percent increase in wholesale non-firm sales. The
revenue per kilowatthour sold in 1998 reflects the 33 percent increase in
wholesale non-firm sales to 371,100 megawatthours. The revenue per kilowatthour
sold in 1997 reflects the increased wholesale sales to MDU's Sheridan, Wyoming
customers and 279,600 megawatthours of wholesale non-firm sales.
Operating expenses have remained fairly stable over the last three years.
Operating expenses increased 2.0 percent in 1999, primarily due to increased
purchase power expense, operations and maintenance expenses and depreciation,
partially offset by lower fuel expense. Operating expenses decreased 3.1 percent
in 1998, primarily due to lower purchased power costs and strong operating cost
management, partially offset by increased property taxes and fuel expense. 1998
purchased power costs declined due to the renegotiated Pacific Power Sales
Agreement. (See ITEM 1. BUSINESS - ELECTRIC POWER SUPPLY - Pacific Power's Power
Sales Agreement.)
Firm energy sales are forecasted to increase over the next 10 years at an annual
compound growth rate of approximately 1 percent with the system demand
forecasted to increase 2 percent. The Company currently has a winter peak of 344
MWs established in December 1998 and a summer peak of 361 MWs established in
July 1999. These forecasts are from studies conducted by the Company with the
help of outside consultants whereby Black Hills Power's service territory is
examined and analyzed to estimate changes in the needs for electrical energy and
demand over a 20-year period. These forecasts are only estimates, and the actual
changes in electric sales may be substantially different. However, in the past
the forecasts tracked actual sales within a band of reasonableness over a period
of several years. Weather deviations can adversely affect energy sales when
compared to forecasts based on normal weather.
Independent Energy Business Unit
- --------------------------------
1999 1998 1997
---- ---- ----
(in thousands)
Revenue:
Coal $ 31,095 $ 31,413 $ 31,080
Gas and oil 10,075 9,204 9,763
Energy marketing 614,228 505,245 142,790
Other 2,977 4,156 3,532
-------- -------- --------
Total revenue 658,375 550,018 187,165
Expenses 644,196 536,048* 172,866
-------- -------- --------
Operating income $ 14,179 $ 13,970* $ 14,299
======== ======== ========
Net income $ 11,882 $ 10,068* $ 10,471
======== ======== ========
EBITDA $ 25,016 $ 22,530 $ 21,672
======== ======== ========
* Excludes $13.5 million pre-tax non-cash charge relating to certain oil
and gas assets ($8.8 million net-of-tax)
Following is a summary of coal, oil and gas production sales and marketing
volumes:
1999 1998 1997
---- ---- ----
Tons of coal sold 3,180,000 3,280,000 3,251,000
Barrels of oil sold 318,000 344,000 299,000
Mcf of natural gas sold
2,791,000 2,056,000 1,747,000
Equivalent barrels
of oil sold 783,000 687,000 590,000
Daily volume (energy marketing):
Natural gas - mmbtus 486,800 487,000 231,000*
Crude oil - barrels 19,270 19,000 12,600*
Coal - tons 4,500 4,400* -
* Since the acquisition date
The combined independent energy business unit's revenues increased 20 percent in
1999 and 194 percent in 1998. In October 1998, the Company acquired a
controlling interest in Enserco Energy, Inc. (this was an equity method
investment of the Company in 1997). In September, 1998, the Company acquired
Black Hills Coal Network, Inc. In July 1997, the Company acquired Black Hills
Energy Resources, Inc. The revenue increases in 1999 and 1998 were primarily the
result of consolidating these three energy marketing companies' operations from
the time of the acquisitions. Additionally, revenues increased in both years as
a result of increased volumes and increased product prices in 1999. The combined
independent energy business unit's operating income and EBITDA (excluding the
non-cash charge in 1998) have been stable during 1999, 1998 and 1997. The
combined independent energy business unit's 1999 net income was improved over
1998 net income (excluding the non-cash charge in 1998) primarily due to record
gas production, improved oil prices, lower depletion expense and the sale of
certain retail gas marketing books in 1999, partially offset by a non-cash
write-down of certain intangible assets relating to the wholesale gas marketing
office in Houston.
Coal Mining
- -----------
Wyodak Resources' coal mining operation has been very stable during the past
three years, producing operating income of $12.6 million, $12.7 million and
$12.2 million in 1999, 1998 and 1997, respectively; net income of $9.7 million,
$9.6 million and $9.1 million in 1999, 1998 and 1997, respectively; and EBITDA
of $15.7 million, $15.6 million and $15.3 million in 1999, 1998 and 1997,
respectively. Wyodak Resources expects decreased sales in 2000 due to a planned
five-week outage at the Wyodak Plant. The decrease in tons of coal produced and
sold in 1999 was primarily the result of a ten-day planned outage at the Wyodak
Plant and a planned outage at one of Black Hills Power's plants.
Oil and Gas
- -----------
Black Hills Exploration and Production's operational results were as follows
(excluding the non-cash charge in 1998 as discussed in the introduction to this
section): operating income of $4.0 million, $1.2 million and $2.9 million in
1999, 1998 and 1997, respectively; net income of $2.5 million, $0.8 million and
$2.1 million in 1999, 1998 and 1997, respectively; and EBITDA of $6.9 million,
$6.4 million and $7.2 million in 1999, 1998 and 1997, respectively. Black Hills
Exploration and Production's record operating income and net income in 1999 are
primarily a result of record natural gas production, higher crude oil prices,
and reduced depletion due to the combination of higher product prices and a
reduced depletable basis due to the non-cash charge in 1998. Black Hills
Exploration and Production's 1998 operating results were decreased primarily as
a result of historically low crude oil prices, which not only reduced revenue
but also increased depletion expense (lower oil and gas prices reduce the
economically recoverable reserve amounts causing an increase in depletion
expense). Black Hills Exploration and Production recognized approximately $2.6
million, $4.9 million and $3.9 million of depletion expense (excluding the
write-down in 1998) in 1999, 1998, and 1997, respectively.
Following is a summary of Black Hills Exploration and Production's oil and gas
reserves at December 31:
1999 1998 1997
---- ---- ----
Barrels of oil (in millions) 4.1 2.4 2.5
Mmcf of natural gas 19.5 16.0 9.1
Black Hills Exploration and Production's reserves are based on reports prepared
by Ralph E. Davis Associates, Inc., an independent consulting and engineering
firm. Reserves were determined using constant product prices at the end of the
respective years. Estimates of economically recoverable reserves and future net
revenues are based on a number of variables, which may differ from actual
results. The increase in reserves at December 31, 1999 was due to improved
drilling results, reserve acquisitions and improved product prices. The increase
in reserves at December 31, 1998 was due to natural gas acquisitions and
improved drilling results despite lower product prices. Black Hills Exploration
and Production intends to increase its net proved reserves by selectively
increasing its oil and gas exploration and development activities and by
acquiring producing properties.
Energy Marketing
- ----------------
The energy marketing companies (Black Hills Energy Resources, Inc., Enserco
Energy, Inc., and Black Hills Coal Network, Inc.) have produced the following
results: operating income (loss) of $(2.4) million, $0.0 million and $(0.8)
million in 1999, 1998 and 1997, respectively; a net loss of $(0.3) million in
each 1999 and 1998 and a $(0.7) million loss in 1997; and EBITDA of $2.5
million, $0.6 million and $(0.7) million in 1999, 1998 and 1997, respectively.
During 1999, the energy marketing companies sold certain of their retail gas
marketing operations, resulting in after-tax gains of approximately $1.8
million. In 1999, revenue and the related cost of sales increased primarily due
to a full year of Black Hills Coal Network operations (acquired in September
1998), increased product prices and increased oil volumes marketed. 1999
operating income was reduced by a non-cash write-down of certain intangible
assets relating to the wholesale gas marketing office in Houston in the amount
of approximately $1.2 million (net-of-tax).
The energy marketing companies generate large amounts of revenue and
corresponding expense related to buying and selling energy products. Energy
marketing is extremely competitive, and margins are typically very small.
Management believes that the synergies the energy marketing companies will
derive from the independent energy business unit's continued growth of its
exploration and production business and expansion into independent power
production will allow the energy marketing companies to generate improved
operating results in future years.
Independent Power Production
- ----------------------------
In 1999, 1998 and 1997 independent power production results were not significant
to the Company. In 2000, the Company believes the independent power production
segment will increase revenues, earnings and cash flow. (see BUSINESS OUTLOOK
STATEMENTS SECTION OF MANAGEMENT'S DISCUSSION AND ANALYSIS.)
Communications Business Unit
- ----------------------------
1999 1998 1997
---- ---- ----
(in thousands)
Revenue $ 278 $ - $ -
Operating expenses 4,852 1,087 471
-------- --------- ---------
Operating loss $ (4,574) $ (1,087) $ (471)
========= ========= =========
Net loss $ (1,262) $ (280) $ (218)
========= ========= =========
EBITDA $ (2,626) $ (570) $ (238)
========= ========= =========
In September 1998, Black Hills Capital Group formed Black Hills FiberCom,
Inc. to provide facilities-based communications services for Rapid City, and the
Northern Black Hills of South Dakota. The communications business unit, through
Black Hills FiberCom, has invested more than $52 million in state-of-the-art
technology that will offer local and long distance telephone service, expanded
cable television service, Internet access, and high-speed data and video
services. Further capital expenditures of approximately $29 million are expected
over the next three years to complete the build out of the fiber optic network
and to acquire (for sale to customers) customer premise equipment.
The Company is marketing the communications services to schools, hospitals,
cities, economic development groups, and business and residential customers, and
began serving customers in late 1999. In 1999, the operating losses were
primarily due to start-up organizational costs, increased depreciation expense
and increased interest expense associated with the capital deployment. By the
end of 2000, management expects to have passed 17,000 homes and serve more than
3,000 business access lines. While continued operating losses are expected as
the build out is completed, management expects that the communications business
unit will have positive cash flow from operating activities by 2001. Management
expects to continue to build value through continued expansion of its network in
this market beyond 2000.
DAKSOFT, Inc. was incorporated by the Company in 1994, to develop and market
internally generated computer software associated with the Company's business
segments. Additionally, DAKSOFT has developed other products and services which
are currently being used internally and marketed to third parties.
Year 2000 Issues
- ----------------
What is referred to as the Year 2000 problem ("Year 2000 problem") is the result
of computer programs being written using two digits rather than four to define
the applicable year. Any of the Company's computer systems and products that
have date-sensitive software may recognize a date using "00" as the Year 1900
rather than the Year 2000. This could result in a system failure or
miscalculations causing disruptions of operations, including, among other
things, a temporary inability to process transactions, send invoices, or engage
in similar normal business activities.
Management had previously formed a Year 2000 Committee to review and ensure the
Company's compliance with what is commonly known as the "Year 2000 problem". In
addition, consultants reviewed the Company's state of readiness. The Company's
review encompassed supporting information technology systems, product generation
and distribution systems, and business supply chain systems and infrastructure.
The cost of either repairing or replacing certain business systems to ensure
business continuance beyond Year 2000 did not have a significant impact on the
results of operations. The cost of the Year 2000 project was funded through
operating cash flows. These costs are primarily attributable to the purchase of
new software and equipment which are expensed or capitalized on a basis
consistent with the Company's accounting policies for capital assets.
Other than seeking representations and assurances from third parties, the
Company has not made an assessment as to whether any of its customers, suppliers
or service providers will be affected by the date change. The Company's
business, financial condition and results of operations may be adversely
impacted should the efforts of customers, suppliers or service providers for the
Company to address the Year 2000 issue prove to be inadequate.
The Company's risk management program includes emergency backup and recovery
procedures to be followed in the event of failure of a business-critical system.
These procedures were to include specific procedures for potential Year 2000
issues. Contingency plans to protect the business from Year 2000-related
interruptions are in place and include, for example, development of backup
procedures, identification of alternate suppliers and possible increases in
safety inventory levels.
Management presently believes that with the modifications made to the Company's
existing software and conversions to new software, the Year 2000 problem has
been mitigated.
Accounting Pronouncements
- --------------------------
In June, 1999, FASB issued Statement of Financial Accounting Standards No. 137
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133." This statement delayed the effective
date of FASB Statement No. 133 until fiscal years beginning after June 15, 2000.
BUSINESS OUTLOOK STATEMENTS
Recent Developments and Acquisitions
- ------------------------------------
Black Hills Generation, Inc. and Black Hills Energy Capital, Inc. represent the
Company's entry into the independent power generation business. In December
1999, Black Hills Generation, Inc. acquired a 50% interest in a limited
liability company that is constructing three gas-fired combustion turbine
peaking units that have a total capacity of approximately 111 megawatts. These
facilities are scheduled to become operational in the second quarter of 2000,
and the production has been sold to Public Service of Colorado under a seven
year tolling arrangement. Ultimately, upon closure of the contemplated Indeck
Capital, Inc. acquisition in 2000 (see next paragraph), the independent energy
business unit will control 100% of these three facilities as Indeck Capital,
Inc. currently owns the other 50% interest. At December 31, 1999, the Company
had funded approximately $52 million of the expected $80 million capital
requirements associated with these three peaking units through notes receivable
from the limited liability company. Management and Indeck Capital, Inc. expect
to close on non-recourse project level financing in the first quarter of 2000
related to these projects.
In January 2000, the Company announced that it had reached a definitive
agreement to acquire 100% of Indeck Capital, Inc. a privately-held independent
power company that owns and operates certain independent power facilities, and
has direct or indirect investments in other independent power facilities. As of
January 1, 2000, Indeck Capital, Inc.'s net megawatt interest in operating
facilities or development projects is approximately 240 megawatts, which are
primarily concentrated in hydro-electric and gas-fired generating facilities.
The pending acquisition is subject to certain conditions of closing, including
regulatory approval, and management expects to close this acquisition during the
first six months of 2000. Indeck Capital, Inc. will be merged into Black Hills
Energy Capital, Inc. upon closure of the acquisition. Management believes this
acquisition, when completed, will have a positive impact on earnings, and will
enable the Company to further its expansion into the independent power
generation business in the future.
Black Hills Generation has begun initial engineering and site preparation to
build an 80 megawatt coal-fired electric generating plant to be known as the
WYGEN Project adjacent to the electric utility business unit's Neil Simpson Unit
#2.
Future Communications Activities
- --------------------------------
The Company's communications operations are expected to have operating losses
for two to four years. The recovery of capital investment and future
profitability are dependent primarily on the ability of the Company to attract
new customers and customers from incumbent providers including U.S. West
Communications and Telecommunications, Inc. (TCI) the incumbent telephone and
cable television providers. Although the Company does not anticipate being
regulated in the local markets it is unable to predict future markets, future
government impositions, and future economic conditions that could affect the
profitability of the communication and technology operations.
Risks and Uncertainties
- -----------------------
In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 ("Reform Act"), the Company is hereby filing
cautionary statements identifying important factors that could cause our actual
results to differ materially from those projected in forward-looking statements
(as such term is defined in the Reform Act) made by or on behalf of the Company
in this Annual Report on Form 10K, Annual Report, quarterly report on Form 10-Q,
and presentations, or in response to questions or otherwise. Any statements that
express or involve discussions as to expectations, beliefs, plans, objectives,
assumptions or future events or performance (often, but not always, through the
use of words or phrases such as "anticipates," "believes," "estimates,"
"expects," "intends," "plans," "predicts," "projects," "will likely result,"
"will continue," or similar expressions) are not statements of historical fact
and may be forward-looking.
Forward-looking statements involve estimates, assumptions, and uncertainties and
are qualified in their entirety by reference to, and are accompanied by, the
following important factors, which are difficult to predict, contain
uncertainties, are beyond our control, and may cause actual results to differ
materially from those contained in forward-looking statements:
o Prevailing governmental policies and regulatory actions, including those of
the Federal Energy Regulatory Commission, the South Dakota Public Utilities
Commission, the Wyoming Public Service Commission and the Montana Public
Service Commission, with respect to allowed rates of return, industry and
rate structure, acquisition and disposal of assets and facilities,
operation and construction of plant facilities, recovery of purchased power
and other capital investments, and present or prospective wholesale and
resale competition (including but not limited to retail wheeling and
transmission costs);
o Economic and geographic factors, including political and economic risk;
o Changes in and compliance with environmental and safety laws and policies;
o Weather conditions;
o Population growth rates and demographic patterns;
o Competition for retail and wholesale customers;
o Pricing and transportation of commodities;
o Market demand, including structural market changes;
o Changes in tax rates or policies or in rates of inflation;
o Changes in project costs;
o Unanticipated changes in operating expenses and/or capital expenditures;
o Capital market conditions;
o Technological advances;
o Competition for new energy development opportunities; and
o Legal and administrative proceedings (whether civil or criminal) and
settlement that influence the business and profitability of the Company.
Any forward-looking statement speaks only as to the date on which that statement
is made, and the Company undertakes no obligation to update any forward-looking
statement to reflect events or circumstances after the date on which that
statement is made or to reflect the occurrence of an anticipated event. New
factors emerge from time to time, and it is not possible for management to
predict all such factors, nor can it assess the impact of any such factor on the
business or the extent to which factor, or combination of factors, may cause
results to differ materially from those contained in any forward-looking
statement.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants 33
Consolidated Statements of Income and Retained Earnings
for the three years ended December 31, 1999 34
Consolidated Statements of Cash Flows for
the three years ended December 31, 1999 35
Consolidated Balance Sheets as of December 31, 1999 and 1998 36
Consolidated Statements of Capitalization as of
December 31, 1999 and 1998 37
Notes to Consolidated Financial Statements 38
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Black Hills Corporation:
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Black Hills Corporation and Subsidiaries as of December 31,
1999 and 1998, and the related consolidated statements of income, retained
earnings and cash flows for each of the three years in the period ended December
31, 1999. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Black Hills Corporation and
Subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota,
January 26, 2000
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31 1999 1998 1997
---- ---- ----
(in thousands, except per share amounts)
Operating revenues:
Electric utility $133,222 $129,236 $126,497
Independent energy 658,375 550,018 187,165
Communications 278 - -
--------- ---------- ---------
791,875 679,254 313,662
--------- ---------- ---------
Operating expenses:
Fuel and purchased power 637,302 531,518 177,071
Operations and maintenance 36,463 32,701 31,743
Administrative and general 18,272 15,747 12,113
Depreciation, depletion and
amortization 25,067 24,037 22,311
Oil and gas ceilings test
write down - 13,546 -
Taxes, other than income
taxes 12,880 12,472 11,985
--------- --------- ---------
729,984 630,021 255,223
--------- --------- ---------
Operating income 61,891 49,233 58,439
--------- --------- ---------
Other income (expense):
Interest expense (15,460) (14,707) (14,123)
Investment income 3,614 2,861 2,136
Other, net 2,811 129 233
---------- --------- ---------
(9,035) (11,717) (11,754)
---------- --------- ---------
Income before income taxes 52,856 37,516 46,685
Income taxes (15,789) (11,708) (14,326)
---------- --------- ---------
Net income $ 37,067 $ 25,808 $ 32,359
========== ========= =========
Earnings per share of common stock:
Basic and diluted $1.73 $1.19 $1.49
========== ========= =========
Weighted average common shares outstanding:
Basic 21,445 21,623 21,692
========== ========= =========
Diluted 21,482 21,665 21,706
========== ========= =========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years ended December 31 1999 1998 1997
---- ---- ----
(in thousands)
Balance, beginning of year $147,774 $143,703 $131,884
Net income 37,067 25,808 32,359
Cash dividends on common stock
($1.04, $1.00 and $0.95 per
share, respectively) (22,602) (21,737) (20,540)
---------- ---------- ----------
Balance, end of year $162,239 $147,774 $143,703
========== ========== ==========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31 1999 1998 1997
---- ---- ----
(in thousands)
Operating activities:
Net income $37,067 $25,808 $32,359
Principal non-cash items-
Depreciation, depletion and amortization 25,067 24,037 22,311
Oil and gas ceilings test write down - 13,546 -
Gain on sales of retail energy marketing assets (2,541) - -
Deferred income taxes and investment tax credits 2,291 (2,535) 2,457
Increase in receivables, inventories and other
current assets (1,771) (49,775) (27,067)
Increase in current liabilities 10,281 43,709 26,015
Other, net 5,284 (60) (26)
---------- ----------- ----------
75,678 54,730 56,049
--------- -------- --------
Investing activities:
Property additions, excluding allowance for other
funds used during construction (104,225) (25,265) (21,087)
Independent power investment (52,319) - -
Energy marketing assets - (1,960) (7,232)
Proceeds from sales of retail energy marketing 3,463 - -
Available for sale securities purchased (7,870) (22,361) (31,944)
Available for sale securities sold 22,959 13,655 29,433
--------- --------- ---------
(137,992) (35,931) (30,830)
---------- --------- ---------
Financing activities:
Dividends paid (22,602) (21,737) (20,540)
Treasury stock purchased (4,949) (3,081) -
Common stock issued 424 273 409
Increase (decrease) in short-term borrowings 92,489 5,067 (120)
Long-term debt retired (1,330) (1,331) (1,534)
---------- ---------- ---------
64,032 (20,809) (21,785)
--------- --------- --------
Increase (decrease) in cash and cash equivalents 1,718 (2,010) 3,434
Cash and cash equivalents:
Beginning of year 14,764 16,774 13,340
--------- --------- --------
End of year $ 16,482 $ 14,764 $16,774
======== ======== =======
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest $18,819 $14,742 $14,167
Income taxes $13,173 $13,135 $11,840
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
At December 31, 1999 1998
---- ----
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 16,482 $ 14,764
Securities available for sale 7,586 22,675
Receivables, net
Customers 84,331 87,068
Other 55,694 2,919
Materials, supplies and fuel 14,278 9,733
Prepaid expenses 2,828 3,321
----------- -----------
181,199 140,480
----------- -----------
Property and equipment:
Electric utility 526,945 501,164
Independent energy 132,331 116,000
Communications 50,621 2,209
Other 591 176
------------ ------------
710,488 619,549
Less accumulated depreciation
and depletion (246,299) (229,942)
------------ ------------
464,189 389,607
------------ ------------
Deferred charges:
Federal income taxes 11,472 12,347
Regulatory asset 3,944 3,978
Other 14,002 13,005
------------ ------------
29,418 29,330
------------ ------------
$674,806 $559,417
============ ============
LIABILITIES AND CAPITALIZATION
Current liabilities:
Current maturities of long-term debt $ 1,330 $ 1,330
Notes payable 97,579 5,090
Accounts payable 80,355 74,087
Accrued liabilities-
Taxes 8,357 9,950
Interest 4,119 3,956
Other 13,612 8,169
------------ -----------
205,352 102,582
------------ -----------
Deferred credits:
Federal income taxes 59,140 55,107
Investment tax credits 3,022 3,514
Reclamation liability 17,315 17,000
Regulatory liability 5,179 5,661
Other 7,492 6,857
------------ -----------
92,148 88,139
------------ -----------
Capitalization, per accompanying statements:
Common stock equity 216,606 206,666
Long-term debt 160,700 162,030
------------ -----------
377,306 368,696
------------ -----------
$674,806 $559,417
============ ===========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1999 1998
---- ----
(in thousands)
Common stock equity:
Common stock $1 par value; 50,000,000 shares authorized;
21,739,030 and 21,719,465 shares outstanding, respectively $ 21,739 $ 21,719
Additional paid-in capital 40,658 40,254
Retained earnings 162,239 147,774
Treasury stock (8,030) (3,081)
----------- -----------
Total common stock equity 216,606 206,666
----------- -----------
Long-term debt:
First mortgage bonds-
6.50% due 2002 15,000 15,000
9.00% due 2003 4,255 5,295
8.06% due 2010 30,000 30,000
9.49% due 2018 5,420 5,710
9.35% due 2021 35,000 35,000
8.30% due 2024 45,000 45,000
----------- ---------
134,675 136,005
----------- ---------
Other-
6.7% pollution control revenue bonds, due 2010 12,300 12,300
7.5% pollution control revenue bonds, due 2024 12,200 12,200
Other long-term obligations 2,855 2,855
----------- ----------
27,355 27,355
----------- ----------
Total long-term debt 162,030 163,360
Current maturities (1,330) (1,330)
----------- ----------
Net long-term debt 160,700 162,030
----------- ----------
Total capitalization $377,306 $368,696
=========== ==========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
(1) BUSINESS DESCRIPTION AND SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES
Business Description
- --------------------
Black Hills Corporation and its subsidiaries operate in three primary business
segments: electric utility, independent energy (includes coal mining, oil and
natural gas operations, energy marketing and independent power production), and
communications. The Company's electric utility operation is engaged in the
generation, purchase, transmission, distribution and sale of electric power and
energy in western South Dakota, northeastern Wyoming and southeastern Montana.
Sales of electric power to the three largest electric customers represented 16
percent of the Company's electric revenue in 1999, 17 percent in 1998 and 18
percent in 1997. The coal mining operation of the Company, located in
northeastern Wyoming, mines and sells sub-bituminous coal primarily under
long-term coal supply agreements. As discussed in Note 6, approximately 80
percent of the coal mining operation's sales are to the Wyodak Plant. Sales of
coal to the Company and to PacifiCorp, herein referred to as Pacific Power,
represent 97 percent of total coal sales in 1999. The Company's oil and gas
exploration and production business operates and has working interests in
properties located in the western and southern United States. The Company's
energy marketing businesses market natural gas, crude oil and coal and provide
related energy services to customers in the West Coast, Northwest, Rocky
Mountain, Southwest, Midwest and East Coast markets. The Company's
communications operations provide communication services to Rapid City and the
Northern Black Hills of South Dakota and a software development and marketing
company.
Principles of Consolidation
- ---------------------------
The consolidated financial statements include the accounts of Black Hills
Corporation and its wholly-owned and majority-owned subsidiaries. The company
owns 51 percent of the voting securities of Black Hills FiberCom LLC. The
minority interest is shown in Other, net in the Consolidated Statements of
Income.
All significant intercompany balances and transactions have been eliminated in
consolidation except for revenues and expenses associated with intercompany coal
sales in accordance with the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." Total intercompany coal sales not eliminated were $7,664,000,
$10,256,000 and $11,089,000 in 1999, 1998, and 1997, respectively.
In 1998, Enserco Energy, Inc. ("Enserco") reacquired the other shareholders'
interests effectively becoming a wholly-owned subsidiary. For the 1998 financial
statements, the Company consolidated Enserco as if it was wholly-owned for the
entire year and reported a minority interest for the portion of net income due
the other shareholders. In 1997, the Company had a 50 percent ownership interest
in Enserco, which was accounted for using the equity method of accounting.
The Company uses the proportionate consolidation method to account for its
working interests in oil and gas properties.
Regulatory Accounting
- ---------------------
Black Hills Power follows the provisions of SFAS No. 71, and its financial
statements reflect the effects of the different ratemaking principles followed
by the various jurisdictions regulating Black Hills Power. As a result of Black
Hills Power's 1995 rate case settlement, a 50-year depreciable life for NS #2 is
used for financial reporting purposes. If Black Hills Power were not following
SFAS 71, a 35 to 40 year life would be more appropriate which would increase
depreciation expense by approximately $600,000 per year. If rate recovery of
generation-related costs becomes unlikely or uncertain, due to competition or
regulatory action, these accounting standards may no longer apply to Black Hills
Power's generation operations. In the event Black Hills Power determines that it
no longer meets the criteria for following SFAS 71, the accounting impact to the
Company would be an extraordinary non-cash charge to operations of an amount
that could be material. Criteria that give rise to the discontinuance of SFAS 71
include increasing competition that could restrict Black Hills Power's ability
to establish prices to recover specific costs and a significant change in the
manner in which rates are set by regulators from cost-based regulation to
another form of regulation. The Company periodically reviews these criteria to
ensure the continuing application of SFAS 71 is appropriate.
Property
- --------
Property is recorded at cost which includes an allowance for funds used during
construction where applicable. The cost of electric property retired, together
with removal cost less salvage, is charged to accumulated depreciation. Repairs
and maintenance of property are charged to operations as incurred.
The Company periodically evaluates assets under SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of,"
which requires that such assets be probable of future recovery at each balance
sheet date. As of December 31, 1999 and 1998, no write-down was required.
Depreciation and Depletion
- --------------------------
Depreciation is computed using the straight-line method over the estimated
useful lives of the related assets. Depreciation provisions for the electric
property were equivalent to annual composite rates of 3.1 percent in 1999 and
3.0 percent in 1998 and 1997. Composite depreciation rates for other property
were 5.7 percent, 7.9 percent, and 8.1 percent in 1999, 1998 and 1997,
respectively. Depletion of coal and oil and gas properties is computed using the
cost method for financial reporting.
Available for Sale Securities
- -----------------------------
The Company has investments in marketable securities which are classified as
available-for-sale securities and are carried at fair value. The difference
between the securities' fair value and cost basis and the realized gains and
losses on sales of the securities were not significant for the periods
presented.
Revenue Recognition
- -------------------
Revenue from sales of electric energy is based on rates filed with applicable
regulatory authorities. Electric revenue includes an accrual for estimated
unbilled revenue for services provided through year-end. Revenue from other
business segments is recognized at the time the products are delivered or the
services are rendered.
Use of Estimates
- ----------------
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Ultimate results could differ from those estimates.
Oil and Gas Operations
- ----------------------
The Company accounts for its oil and gas activities under the full cost method.
Under the full cost method, all productive and nonproductive costs related to
acquisition, exploration and development drilling activities are capitalized.
These costs are amortized using a unit-of-production method based on volumes
produced and proved reserves. Under the full cost method, net capitalized costs
may not exceed the present value of proved reserves.
Allowance for Funds Used During Construction
- --------------------------------------------
Allowance for funds used during construction (AFDC) represents the approximate
composite cost of borrowed funds and a return on capital used to finance
construction expenditures and is capitalized as a component of the electric
property. The AFDC was computed at an annual composite rate of 8.3 percent in
1999, 10.1 percent in 1998 and 10.0 percent in 1997.
Income Taxes
- ------------
The Company follows the provisions of SFAS No. 109, "Accounting for Income
Taxes," which requires the use of the liability method in accounting for income
taxes. Under the liability method, deferred income taxes are recognized, at
currently enacted income tax rates, to reflect the tax effect of temporary
differences between the financial and tax bases of assets and liabilities. Such
temporary differences are the result of provisions in the income tax law that
either require or permit certain items to be reported on the income tax return
in a different period than they are reported in the financial statements. To the
extent such income taxes are recoverable or payable through future rates,
regulatory assets and liabilities have been recorded in the accompanying
consolidated balance sheets.
Deferred taxes are provided on all significant temporary differences,
principally depreciation and depletion. Investment tax credits have been
deferred in the electric operation and the accumulated balance is amortized as a
reduction of income tax expense over the useful lives of the related electric
property which gave rise to the credits.
Price Risk Management
- ---------------------
Effective January 1, 1999, the Company adopted the provisions of Emerging Issues
Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management
Activities" ("EITF 98-10") pursuant to the implementation requirements stated
therein. The resulting effect of adoption of the provisions of EITF 98-10 was to
alter the Company's comprehensive method of accounting for energy-related
contracts, as defined in that statement. The effect of the adoption of EITF
98-10 was not material to the 1999 results of operations.
The Company now accounts for all energy trading activities at fair value as of
the balance sheet date and recognizes currently the net gains or losses
resulting from the revaluation of these contracts to fair value in its results
of operations. As a result, substantially all of the operations of the Company's
gas marketing, crude oil marketing and coal marketing operations are now
accounted for under a fair value accounting methodology. Generally, revenue
recognition for the Company's coal, oil and natural gas production activities,
as well as its power generation businesses, remain on an accrual-based
accounting methodology. Sales and purchases by these businesses are not trading
operations, as defined in the statement, and therefore not subject to the
provisions of EITF 98-10.
For their non-trading activities, the Company utilizes deferral (hedge)
accounting in conjunction with such financial instruments; gains or losses from
changes in the market value of the financial instruments are deferred until the
gain or loss on the hedged item is recognized for non-trading activities.
Financial instruments are classified as being used for a hedge only if the
instrument reduces the risk of the underlying hedged item and is designated at
the inception as a hedge with respect to the hedged item.
The Company continues to analyze the effects of adoption of the rules
promulgated by Financial Accounting Standard No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("Statement No. 133"). Provisions in
Statement No. 133 will affect the accounting and disclosure of contractual
arrangements and operations of the Company.
Management believes the adoption of the provisions of Statement No. 133 may
affect the variability of future periodic results reported by the Company, as
well as its competitors, as market conditions and resulting valuations change
from time to time. Such earnings variability, if any, will likely result
principally from valuation issues arising from imbalances between supply and
demand created by illiquidity in certain commodity markets resulting from, among
other things, a lack of mature trading and price discovery mechanisms,
transmission and/or transportation constraints resulting from regulation or
other issues in certain markets and the need for a representative number of
market participants maintaining the financial liquidity and other resources
necessary to compete effectively. Management will monitor exposure to these and
other market and business risks and will adjust valuation factors accordingly as
indicated by changing circumstances.
Accounting Pronouncements
- -------------------------
In June, 1999, FASB issued Statement of Financial Accounting Standards No.
137 "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133." This statement delayed the
effective date of SFAS No. 133 until fiscal years beginning after June 15, 2000.
Reclassifications
- -----------------
Certain 1998 and 1997 amounts in the financial statements have been reclassified
to conform to the 1999 presentation. These reclassifications did not have an
effect on the Company's stockholders' investment or results of operations.
(2) CAPITAL STOCK
In January, 1998, the Board of Directors declared a 3-for-2 Common Stock Split
effected in the form of a stock dividend. The stock dividend was paid March 10,
1998 to shareholders of record on February 13, 1998. The common stock share and
per share information in the accompanying consolidated financial statements and
notes reflect the stock distribution.
Net Income Per Share
- --------------------
The Company follows SFAS No. 128 "Earnings Per Share", which requires the
presentation of basic and diluted earnings per share. Basic earnings per share
is computed by dividing net income available to common shareholders by the
weighted average number of common shares outstanding during each year. Diluted
earnings per share is computed under the treasury stock method and is calculated
to compute the dilutive effect of outstanding stock options.
A reconciliation of these amounts is as follows (in thousands, except per share
data):
1999 1998 1997
---- ---- ----
Net income $37,067 $25,808 $32,359
======= ======= =======
Weighted average
common shares
outstanding-basic 21,445 21,623 21,692
Dilutive effect of
option plan 37 42 14
------- ------- -------
Common and
potential common
shares outstanding-
diluted 21,482 21,665 21,706
====== ====== ======
Basic and diluted net
income per share $1.73 $1.19 $1.49
===== ===== =====
Common Stock
- ------------
The Company has a stock option plan ("the Stock Option Plan") which allows for
the granting of stock options with exercise prices equal to the stocks' market
value on the date of grant and an employee stock purchase plan ("the ESPP
Plan"). The Company accounts for such plans under Accounting Principles Board
Opinion No. 25, under which no compensation cost has been recognized.
Had compensation cost been determined consistent with SFAS No. 123, the
Company's net income and earnings per share would have been reduced to the
following proforma amounts:
1999 1998 1997
---- ---- ----
(in thousands)
Net income:
As reported $37,067 $25,808 $32,359
Proforma $36,877 $25,717 $32,308
Earnings per share (basic and diluted):
As reported $1.73 $1.19 $1.49
Proforma $1.72 $1.19 $1.49
The Company may grant options for up to 1,000,000 shares of common stock under
the Stock Option Plan. The Company has granted options on 431,950 shares and
292,700 shares through December 31, 1999 and 1998, respectively. In 1999,
options on 1,000 shares were forfeited. No options were forfeited in 1998. No
options were exercised in 1999. Options on 3,000 shares were exercised in 1998
at $22.88 per share and an exercise price of $16.67 per share. The option
exercise price equals the fair market value of the stock on the day of the
grant. The options granted have an exercise price range of $16.67 to $25.00. The
options granted vest one-third a year for three years and all expire after ten
years from the grant date. At December 31, 1999 182,400 options were available
for exercise at an exercise price range of $16.67 to $25.00. At December 31,
1998, 84,800 options were available for exercise at an exercise price range of
$16.67 to $22.50. At December 31, 1997, 27,900 options were available for
exercise at an exercise price of $16.67.
The fair value of each option grant is estimated on the date of grant using the
Black Scholes option pricing model with the following weighted-average
assumptions used for the grants:
1999 1998 1997
---- ---- ----
Risk free interest rate 5.92% 5.50% 6.09%
Expected dividend yield 4.50% 4.20% 5.00%
Expected life 10 years 10 years 10 years
Expected volatility 17.66% 16.67% 16.71%
Weighted average
fair value $1.17 $0.61 $1.09
The Company issued 19,565, 12,824 and 29,294 shares of common stock under the
ESPP Plan in 1999, 1998 and 1997, respectively. At December 31, 1999, 247,570
shares are reserved and available for issuance under the ESPP Plan. The Company
sells the shares to employees at 90 percent of the stock's market price on the
offering date. The fair value per share of shares sold in 1999 was $24.07.
The Company has a Dividend Reinvestment and Stock Purchase Plan under which
shareholders may purchase additional shares of common stock through dividend
reinvestment and/or optional cash payments at 100 percent of the recent average
market price. The Company has the option of issuing new shares or purchasing the
shares on the open market. The Company purchased shares on the open market in
1999, 1998 and 1997. At December 31, 1999, 1,290,797 shares of unissued common
stock were available for future offerings under the Plan.
Additional Paid-in Capital
- --------------------------
Changes in additional paid-in capital for the years indicated were:
1999 1998 1997
---- ---- ----
(in thousands)
Balance, beginning of year $40,254 $39,995 $46,841
Stock Dividend for 3-for-2
Common Stock split - - (7,235)
Premium, net of expenses
from sales of stock 404 259 389
--------- --------- ---------
Balance, end of year $40,658 $40,254 $39,995
========= ========= =========
Treasury Stock
In April 1999, the Board of Directors authorized the acquisition of up to
700,000 shares of the Company's Common Stock on the open market to fund possible
future acquisitions by the Company, for its Employee Stock Option Plan and for
other general purposes.
A subsidiary of the Company was authorized to repurchase up to 600,000 shares of
common stock for similar purposes. At December 31, 1999, a subsidiary of the
Company had reacquired 367,509 shares at an average price of $22.95 per share.
(3) LONG-TERM DEBT
Substantially all of the Company's utility property is subject to the lien of
the Indenture securing its first mortgage bonds. First mortgage bonds of the
Company may be issued in amounts limited by property, earnings and other
provisions of the mortgage indentures. Scheduled maturities of long-term debt
for the next five years are: $1,330,000 in 2000, $3,029,000 in 2001, $18,018,000
in 2002, $3,068,000 in 2003 and $1,955,000 in 2004.
(4) NOTES PAYABLE
The Company had $115,000,000 and $12,000,000 of unsecured short-term lines of
credit at December 31, 1999 and 1998 respectively. There was $96,640,000 and
$3,850,000 outstanding under these lines of credit at December 31, 1999 and 1998
respectively. The Company has no compensating balance requirements associated
with these lines of credit. The lines of credit are subject to periodic review
and renewal during the year by the banks.
In addition to the above lines of credit, Black Hills Energy Resources, Inc. has
a $25,000,000, uncommitted, discretionary credit facility. The transactional
line of credit provides credit support for the purchases of natural gas and
crude oil of Black Hills Energy Resources. The Company and its subsidiaries
provide no guarantee to the Lender. At December 31, 1999, and 1998, Black Hills
Energy Resources had letters of credit outstanding of $13,154,000 and
$27,990,000, respectively, and no balance outstanding on the overdraft line of
credit.
In addition to the above lines of credit, Wyodak Resources has guaranteed a
$25,000,000 line of credit for Enserco to use to guarantee letters of credit.
Enserco pays a 0.125 percent facility fee on this line of credit. At December
31, 1999 and 1998, there were no balances outstanding on this line of credit. At
December 31, 1999, Enserco Energy had $19,900,000 in outstanding letters of
credit.
(5) FAIR VALUE OF FINANCIAL
INSTRUMENTS
Cash of the Company is invested in money market investments such as municipal
put bonds, money market preferreds, commercial paper, Eurodollars and
certificates of deposit. The Company considers all highly liquid investments
with an original maturity of three months or less to be cash equivalents. The
following methods and assumptions were used to estimate the fair value of each
class of the Company's financial instruments.
Cash and Cash Equivalents
- -------------------------
The carrying amount approximates fair value due to the short maturity of these
instruments.
Available for Sale Securities
- -----------------------------
The fair value of the Company's investments equals the quoted market price when
available and a quoted market price for similar securities if a quoted market
price is not available. The Company has classified all of its marketable
securities as available-for-sale as of December 31, 1999 and 1998, and the fair
value approximates cost.
Long-Term Debt
- --------------
The fair value of the Company's long-term debt is estimated based on quoted
market rates for utility debt instruments having similar maturities and similar
debt ratings. The Company's outstanding bonds are either currently not callable
or are subject to make-whole provisions which would eliminate any economic
benefits for the Company to call and refinance the bonds. The estimated fair
values of the Company's financial instruments are as follows:
1999
----
(in thousands)
Carrying Fair
Amount Value
-------- --------
Cash and cash equivalents $ 16,482 $ 16,482
Securities available for sale:
Certificates of deposit 550 550
Federal, state and local
agency obligations 7,036 7,036
Long-term debt 162,030 165,958
1998
----
(in thousands)
Carrying Fair
Amount Value
-------- --------
Cash and cash equivalents $ 14,764 $ 14,764
Securities available for sale:
Corporate debt securities 1,997 1,997
Federal, state and local
agency obligations 20,678 20,678
Long-term debt 163,360 189,767
(6) WYODAK PLANT
The Company owns a 20 percent interest and Pacific Power an 80 percent interest
in the Wyodak Plant (the Plant), a 330 megawatt coal-fired electric generating
station located in Campbell County, Wyoming. Pacific Power is the operator of
the Plant. The Company receives 20 percent of the Plant's capacity and is
committed to pay 20 percent of its additions, replacements and operating and
maintenance expenses. As of December 31, 1999, the Company's investment in the
Plant included $72,228,000 in electric plant and $24,028,000 in accumulated
depreciation. The Company's share of direct expenses of the Plant was
$4,940,000, $5,835,000 and $5,934,000 for the years ended December 31, 1999,
1998 and 1997, respectively, and is included in the corresponding categories of
operating expenses in the accompanying consolidated statements of income. Wyodak
Resources supplies coal to the Plant under an agreement expiring in 2013 with a
Pacific Power option to renew for 10 years. This coal supply agreement is
collateralized by a mortgage on and a security interest in some of Wyodak
Resources' coal reserves. At December 31, 1999, approximately 19,934,000 tons
were covered under this agreement. Wyodak Resources' sales to the Plant were
$24,883,000, $23,228,000 and $22,688,000, for the years ended December 31, 1999,
1998 and 1997, respectively.
(7) COMMITMENTS AND CONTINGENT LIABILITIES
MDU Power Sale
- --------------
On January 1, 1997, the Company began service under a ten year contract to
supply up to 55 megawatts of electric power and associated energy required by
MDU for its Sheridan, Wyoming, service territory. The service area experienced a
44 megawatt peak in 1999 and a 47 megawatt peak in both 1998 and 1997. The load
factor was approximately 57 percent for all three years.
Coal Obligations
- ----------------
In addition to the 19,934,000 tons of coal reserved under the agreement to
supply coal to the Wyodak Plant, Wyodak Resources has reserved 24,150,000 tons
of coal under existing contracts.
Coal Leases
- -----------
Wyodak Resources' mining rights to its coal are based upon four federal leases
and one state lease. The federal leases provide for a royalty of 12.5 percent of
the selling price of the coal. The state lease provides for a royalty, approved
in 1998, currently at 9 percent. Wyodak Resources paid royalties in the amount
of $3,968,000, $4,009,000 and $3,969,000 in 1999, 1998, and 1997, respectively.
Each federal lease requires diligent development to produce at least one percent
of all recoverable reserves within either 10 years from the respective dates of
the leases or 10 years from the date of adjustment of the leases. Each lease
further requires a continuing obligation to mine, thereafter, at an average
annual rate of at least one percent of the recoverable reserves. All of the
federal leases constitute one logical mining unit which is treated as one lease
for the purpose of determining diligent development and continuing operation
requirements.
Pacific Power's Power Sales Agreement
- -------------------------------------
In 1983 the Company entered into a 40 year power agreement with Pacific Power
providing for the purchase by the Company of 75 megawatts of electric capacity
and energy from Pacific Power's system. The price paid for the capacity and
energy is based on the operating costs of one of Pacific Power's coal-fired
electric generating plants. Costs incurred under this agreement were
$17,778,000, $17,458,000 and $20,251,000 in 1999, 1998 and 1997, respectively.
Reclamation
- -----------
Under its mining permit, Wyodak Resources is required to reclaim all land where
it has mined coal reserves. The cost of reclaiming the land is accrued as the
coal is mined. While the reclamation process takes place on a continual basis,
much of the reclamation occurs over an extended period after the area is mined.
Approximately $700,000 is charged to operations as reclamation expense annually.
As of December 31, 1999, accrued reclamation costs were approximately
$17,315,000.
Price Risk Management Activities
- --------------------------------
The primary financial instruments the Company uses in managing its price risk
exposure are exchange traded natural gas futures contracts, over-the-counter
natural gas and crude oil swaps, collar and option contracts. The Company would
be exposed to credit losses in the event of nonperformance by the counterparties
that have issued the financial instruments. The Company does not expect that the
counterparties will fail to meet their obligations, based on the Company's
review of the financial condition of the counterparties and/or their credit
ratings.
The Company, through its independent energy business unit, utilizes derivatives
for its energy marketing services. These financial instruments include fixed
price swap agreements, variable price swap agreements, basis swap agreements,
exchange-traded energy futures contracts, and swaps and collars traded in the
over-the-counter financial markets.
The derivatives are not held for speculative purposes but rather serve to hedge
the Company's exposure related to commodity purchases or sale commitments. Under
Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and
Risk Management Activities" ("EITF 98-10"), these transactions qualify as
trading activities which must be accounted for at fair value. As such, realized
and unrealized gains (losses) are recorded as a component of income.
Additionally, because of the Company's back-to-back transaction strategy, gains
or losses only exist to the extent that the transactions are not effectively
matched. Because the Company does not speculate with "open" positions
substantially all of its trading activities are "back-to-back" positions where a
commitment to buy a commodity is matched with a committed sale or a financial
instrument. During 1999, gains or losses on trading activities were not
significant.
The quantities and maximum terms of derivative financial instruments held for
trading purposes at December 31, 1999 and 1998 are as follows:
Max.
Volume Covered Term
December 31, 1999 (MMBtu's) (Years)
- ----------------- -------------- -------
Natural gas futures
contracts purchased 860,000 1
Natural gas basis swaps
purchased 17,741,500 4
Natural gas basis swaps
sold 18,390,517 4
Natural gas fixed for
float swaps purchased 9,490,486 1
Natural gas fixed for
float swaps sold 10,994,521 1
Natural gas collar
transactions; puts
purchased, calls sold 408,500 1
Natural gas collar
transactions; calls
purchased, puts sold 318,500 1
Max.
Volume Covered Term
December 31, 1998 (MMBtu's) (Years)
- ----------------- -------------- -------
Natural gas futures
contracts purchased 1,470,000 2
Natural gas swap
contracts purchased 7,989,096 3
Natural gas swap
contracts sold 1,473,000 1
To reduce risk from fluctuations in the price of oil and natural gas, the
Company enters into futures and swap transactions. The transactions are used to
hedge price risk from sales of the Company's crude oil and natural gas
production. For such transactions, the Company utilizes hedge accounting. (See
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Note 1 - BUSINESS DESCRIPTION AND
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Price Risk Management.)
At December 31, 1999, the Company had fixed rate for floating rate price swaps
sold for 20,000 barrels per month for the year 2000 to hedge its crude oil price
risk, with a fair value of $(0.5) million at December 31, 1999. At December 31,
1998, the Company did not have material crude oil derivatives in its non-trading
activities. At December 31, 1997, the company had price collars and fixed rate
for floating rate price swaps to hedge crude oil price risk for 15,000 barrels
of oil per month, resulting in the recognition of $0.9 million of gains during
1998.
Other
- -----
The Company is subject to various legal proceedings and claims which arise in
the ordinary course of operations. In the opinion of management, the amount of
liability, if any, with respect to these actions would not materially affect the
consolidated financial position or results of operations of the Company.
(8) EMPLOYEE BENEFIT PLANS
The Company has a defined benefit pension plan (the Plan) covering substantially
all employees. The benefits are based on years of service and compensation
levels during the highest five consecutive years of the last ten years of
service. The Company's funding policy is in accordance with the federal
government's funding requirements. The Plan's assets consist primarily of equity
securities and cash equivalents.
The Company has amended the plan to change the benefit formula for participant
service after February 1, 2000, in conjunction with a new Company match in the
401(k) plan. Additional amendments were made to increase retirement benefits for
pensioners who retired prior to January 1, 1995 and to adjust survivor benefits.
The combined impact of the amendments was to increase the net pension expense by
$170,000 and to increase the projected benefit obligation by $1,846,000.
Net pension (income) expense for the Plan was as follows:
1999 1998 1997
---- ---- ----
(in thousands)
Service cost $ 1,174 $ 895 $ 931
Interest cost 2,598 2,406 2,383
Return on assets:
Actual (12,477) (2,007) (10,278)
Deferred 8,314 (2,412) 7,022
-------- ------- --------
Net pension (income)
expense $ (391) $(1,118) $ 58
======== ======= ========
Actuarial assumptions:
Discount rate 6.75% 7.5% 7.5%
Expected long-term rate
of return on assets 10.5% 10.5% 10.5%
Rate of increase in
compensation levels 5% 5% 5%
Funding information for the Plan as of October 1 each year was as follows (the
discount rate assumption for obligations at 1999 was 7.5% and at 1998 was
6.75%):
1999 1998
---- ----
(in thousands)
Fair value of plan assets $51,212 $40,638
Projected benefit obligation (39,615) (39,490)
-------- --------
11,597 1,148
Unrecognized:
Net gain (12,105) (200)
Prior service cost 2,285 528
Transition asset (90) (180)
-------- --------
Prepaid pension cost $ 1,687 $ 1,296
======== ========
Accumulated benefit obligation $31,914 $31,323
======== ========
Vested benefit obligation $29,214 $29,829
======== ========
A reconciliation of the beginning and ending balances of the projected benefit
obligation is as follows:
1999 1998 1997
---- ---- ----
(in thousands)
Beginning projected
benefit obligation $39,490 $33,025 $32,722
Service cost 1,174 895 931
Interest cost 2,598 2,406 2,383
Actuarial gains (losses) (3,590) 4,968 (1,215)
Benefits paid (1,903) (1,804) (1,796)
Plan amendments 1,846 - -
------- ------- -------
Net increase 125 6,465 303
------- ------- -------
Ending projected
benefit obligation $39,615 $39,490 $33,025
======= ======= =======
A reconciliation of the fair value of plan assets as of October 1 of each year
is as follows:
1999 1998
---- ----
(in thousands)
Beginning market value
of plan assets $40,638 $40,435
Benefits paid (1,903) (1,804)
Investment income 12,477 2,007
------- -------
Ending market value
of plan assets $51,212 $40,638
======= =======
The Company has various supplemental retirement plans for outside directors and
key executives of the Company. The plans are nonqualified defined benefit plans.
Expenses recognized under the plans were $426,548, $395,000 and $94,000 in 1999,
1998, and 1997, respectively. The Company follows the provisions of SFAS No.
106, "Employers' Accounting for Postretirement Benefits Other Than Pensions."
The standard requires that the expected cost of these benefits must be charged
to expense during the years that the employees render service. Prior to adopting
the standard in 1993, the Company expensed these benefits as they were paid. The
Company is amortizing the transition obligation of $2,996,000 over a 20 year
period.
Employees retiring from the Company on or after attaining age 55 who have
rendered at least five years of service to the Company are entitled to
postretirement healthcare benefits coverage. These benefits are subject to
premiums, deductibles, copayment provisions and other limitations. The Company
may amend or change the plan periodically. The Company is not pre-funding its
retiree medical plan.
The net periodic postretirement cost for the Company was as follows:
1999 1998 1997
---- ---- ----
(in thousands)
Service cost $225 $135 $168
Interest cost 362 290 329
Amortization of transition
obligation 150 150 150
Amortization of (gain)/loss 1 (42) (5)
---- ---- ----
$738 $533 $642
==== ==== ====
Funding information as of October 1 was as follows:
1999 1998
---- ----
(in thousands)
Accumulated postretirement benefit
obligation:
Retirees $2,608 $1,821
Fully eligible active participants 1,195 1,033
Other active participants 3,278 2,576
------- -------
Unfunded accumulated postretirement
benefit obligation 7,081 5,430
Unrecognized net loss (1,667) (301)
Unrecognized transition obligation (1,947) (2,097)
------- -------
$3,467 $3,032
======= =======
For measurement purposes, a 9.0 percent annual rate of increase in healthcare
benefits was assumed for 1999; the rate was assumed to decrease gradually to 6
percent in 2005 and remain at that level thereafter. The healthcare cost trend
rate assumption has a significant effect on the amounts reported. A one percent
increase in the healthcare cost trend assumption would increase the service and
interest cost $150,377 or 25.6% and the net periodic postretirement cost
$203,090 or 27.5%. A one percent decrease would reduce the service and interest
cost by $113,659 or 19.3% and decrease the net periodic postretirement cost
$122,663 or 16.6%. The weighted-average discount rate used in determining the
accumulated postretirement benefit obligation was 7.5 percent.
(9) INCOME TAXES
Income tax expense for the years indicated was:
1999 1998 1997
---- ---- ----
(in thousands)
Current $13,498 $14,243 $11,869
Deferred 2,931 (1,886) 3,107
Tax credits, net (640) (649) (650)
------- ------- -------
$15,789 $11,708 $14,326
======= ======= =======
The temporary differences which gave rise to the net deferred tax liability at
December 31, 1999 and 1998 were as follows:
Net Deferred
Income
Tax Asset
December 31, 1999 Assets Liabilities (Liability)
------ ----------- -----------
(in thousands)
Accelerated depreciation and other plant-related differences $ - $48,223 $(48,223)
Regulatory asset 1,792 - 1,792
Regulatory liability - 1,380 (1,380)
Unamortized investment tax credits 1,058 - 1,058
Mining development and oil exploration 3,605 6,893 (3,288)
Employee benefits 2,833 695 2,138
Other 2,184 1,949 235
--------- --------- ---------
$11,472 $59,140 $(47,668)
========= ========= =========
Net Deferred
Income
Tax Asset
December 31, 1998 Assets Liabilities (Liability)
------ ----------- -----------
(in thousands)
Accelerated depreciation and other plant-related
differences $ - $47,095 $(47,095)
Regulatory asset 1,963 - 1,963
Regulatory liability - 1,392 (1,392)
Unamortized investment tax credits 1,230 - 1,230
Mining development and oil exploration 5,481 5,746 (265)
Employee benefits 2,623 494 2,129
Other 1,050 380 670
--------- ---------- -----------
$12,347 $55,107 $(42,760)
======= ======= ========
The effective tax rate differs from the federal statutory rate for the years
ended December 31, as follows:
1999 1998 1997
---- ---- ----
Federal statutory rate 35.0% 35.0% 35.0%
Regulatory asset recognition (0.9) (0.7) (1.3)
Amortization of investment tax credits (1.1) (1.3) (1.1)
Tax-exempt interest income (0.5) (1.1) (0.9)
Percentage depletion in excess of cost (1.6) (1.7) (0.7)
Other (1.0) 1.0 (0.3)
---- ---- ----
29.9% 31.2% 30.7%
==== ==== ====
(10) OIL AND GAS RESERVES (Unaudited)
Black Hills Exploration and Production has interests in 582 producing oil and
gas properties in seven states. Black Hills Exploration and Production also
holds leases on approximately 132,162 net undeveloped acres.
The following table summarizes Black Hills Exploration and Production's
quantities of proved developed and undeveloped oil and natural gas reserves,
estimated using constant year-end product prices, as of December 31, 1999, 1998
and 1997, and a reconciliation of the changes between these dates. These
estimates are based on reserve reports by Ralph E. Davis Associates, Inc. (an
independent engineering company selected by the Company). Such reserve estimates
are based upon a number of variable factors and assumptions which may cause
these estimates to differ from actual results.
1999 1998 1997
---- ---- ----
Oil Gas Oil Gas Oil Gas
(in thousands of barrels of oil and MMCF of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year 2,368 15,952 2,495 9,052 2,386 10,972
Production (309) (2,801) (353) (2,068) (299) (1,747)
Additions 376 7,718 1,149 10,721 1,146 3,498
Property sales (164) (66) - - (10) (393)
Revisions to previous estimates 1,838 (1,343) (923) (1,753) (728) (3,278)
------- ------- ------- ------- ------- -------
Balance at end of year 4,109 19,460 2,368 15,952 2,495 9,052
======= ======= ======= ======= ======= =======
Proved developed reserves at end of
year included above 2,819 14,391 1,463 10,041 2,035 6,821
======= ======= ======= ======= ======= =======
Year-end prices $24.28 $1.99 $9.16 $1.93 $16.34 $2.32
====== ===== ===== ===== ====== =====
In December 1998, Black Hills Exploration and Production recognized a
$13,546,000 pretax loss related to a write down of oil and gas properties. The
write down was primarily due to historically low crude oil prices, lower natural
gas prices and decline in value of certain unevaluated properties.
(11) BUSINESS SEGMENTS
The Company follows FASB Statement No. 131, "Disclosure About Segments of an
Enterprise and Related Information." Black Hills Corporation's business segments
include: Electric which supplies electric utility service to western South
Dakota, northeastern Wyoming and southeastern Montana; Independent Energy
consisting of: Mining which engages in the mining and sale of coal from its mine
near Gillette, Wyoming; Oil and Gas which produces, explores and operates oil
and gas interests located in the Rocky Mountain region, Texas, California and
other states; Energy Marketing which markets natural gas, oil, coal and related
services to customers in the East Coast, Midwest, Southwest, Rocky Mountain,
West Coast and Northwest Regions markets and Independent Power activities and
Communications and Others which primarily markets communications and software
development services.
Financial data for the business segments are as follows (in thousands):
ASSETS Independent Energy
--------------------------------------------
Oil Energy Independent Communications
At December 31, 1999 Electric Mining And Gas Marketing Power & Others Eliminations Total
--------- -------- -------- --------- ----------- -------------- ------------ ----------
Current assets $ 93,837 $ 57,393 $ 1,988 $ 79,709 $ 52,471 $ 9,732 $ (113,931) $ 181,199
Total assets 528,164 137,762 32,724 94,692 52,690 72,785 (244,011) 674,806
At December 31, 1998
Current assets $ 43,760 $ 25,538 $ 1,335 $ 77,397 $ 4 $ 6,406 $ (13,960) $ 140,480
Total assets 451,404 93,140 26,666 86,243 57 18,838 (116,931) 559,417
Independent Energy
--------------------------------------------
YEAR TO DATE Oil Energy Independent Communications
December 31, 1999 Electric Mining And Gas Marketing Power & Others Eliminations Total
--------- -------- -------- --------- ----------- -------------- ------------ -----------
Electric revenues $ 133,222 $ - $ - $ - $ - $ - $ - $ 133,222
Coal revenues - 31,095 - 39,212 - - - 70,307
Gas revenues - - 5,399 382,809 - - - 388,208
Oil revenues - - 4,676 192,207 - - - 196,883
Other revenues - - 2,977 - - 3,423 (3,145) 3,255
--------- -------- -------- --------- ----------- -------------- ------------ -----------
Total revenues $ 133,222 $ 31,095 $ 13,052 $ 614,228 $ - $ 3,423 $ (3,145) $ 791,875
--------- -------- -------- --------- ----------- -------------- ------------ -----------
Depreciation, depletion
& amortization $ 15,552 $ 3,259 $ 2,953 $ 2,757 $ - $ - $ 546 $ 25,067
Operating income
(loss) 52,286 12,606 3,978 (2,248) (157) (4,574) - 61,891
Interest expense 13,830 689 568 245 111 17 - 15,460
Income taxes 12,446 3,439 968 50 (58) (1,056) - 15,789
Net income (loss) 27,362 9,714 2,462 (185) (109) (1,262) (915) 37,067
Property additions 31,911 5,422 9,968 5,947 - 50,977 - 104,225
Independent Energy
--------------------------------------------
YEAR TO DATE Oil Energy Independent Communications
December 31, 1998 Electric Mining And Gas Marketing Power & Others Eliminations Total
--------- -------- -------- --------- ----------- -------------- ------------ -----------
Electric revenues $ 129,236 $ - $ - $ - $ - $ - $ - $ 129,236
Coal revenues - 31,413 - 12,924 - - - 44,337
Gas revenues - - 4,073 375,136 - - - 379,209
Oil revenues - - 5,131 117,185 - - - 122,316
Other revenues - - 3,358 798 - 2,437 (2,437) 4,156
--------- -------- -------- ---------- ----------- -------------- ------------ -----------
Total revenues $ 129,236 $31,413 $ 12,562 $ 506,043 $ - $ 2,437 $ (2,437) $ 679,254
--------- -------- -------- ---------- ----------- -------------- ------------ -----------
Depreciation, depletion
& amortization $ 14,881 $3,252 $ 18,760* $ 690 $ - $ - $ - $ 37,583
Operating income
(loss) 49,896 12,723 (12,340)* 41 - (1,087) - 49,233
Interest expense 13,572 9 355 731 - 40 - 14,707
Income taxes 12,612 4,092 (4,689)* (116) - (191) - 11,708
Net income (loss) 24,825 9,585 (7,976)* (346) - (280) - 25,808
Property additions 11,451 1,447 10,169 424 - 1,774 - 25,265
Increase in goodwill - - - 1,960 - - - 1,960
*Includes the impact of a $13,546 million pretax write down of certain oil and
natural gas properties
Independent Energy
--------------------------------------------
YEAR TO DATE Oil Energy Independent Communications
December 31, 1997 Electric Mining And Gas Marketing Power & Others Eliminations Total
--------- -------- -------- --------- ----------- -------------- ------------ -----------
Electric revenues $ 126,497 $ - $ - $ - $ - $ - $ - $ 126,497
Coal revenues - 31,080 - - - - - 31,080
Gas revenues - - 4,223 95,980 - - - 100,203
Oil revenues - - 5,540 46,810 - - - 52,350
Other revenues - - 3,532 - - 685 (685) 3,532
--------- -------- -------- --------- ----------- --------------- ------------ -----------
Total revenues $ 126,497 $ 31,080 $ 13,295 $ 142,790 $ - $ 685 $ (685) $ 313,662
--------- -------- -------- --------- ----------- --------------- ------------ -----------
Depreciation, depletion
& amortization $ 14,608 $ 3,188 $ 4,275 $ 240 $ - $ - $ - $ 22,311
Operating income
(loss) 44,611 12,217 2,907 (825) - (471) - 58,439
Interest income 13,676 5 203 203 - 36 - 14,123
Income taxes 9,929 4,205 629 (347) - (90) - 14,326
Net income (loss) 22,106 9,073 2,147 (749) - (218) - 32,359
Property additions 12,484 1,336 7,076 - - 191 - 21,087
Increase in goodwill - - - 7,232 - - - 7,232
(12) SUPPLEMENTARY INCOME STATEMENT INFORMATION
Taxes Other than Income Taxes
1999 1998 1997
---- ---- ----
(in thousands)
Property $ 5,449 $ 4,993 $ 4,326
Production and severance 3,264 3,437 3,654
Payroll 1,509 1,348 1,332
Black lung 1,311 1,324 1,310
Federal reclamation 1,113 1,148 1,138
Other 234 222 225
------- ------- -------
$12,880 $12,472 $11,985
======= ======= =======
(13) QUARTERLY HISTORICAL DATA (Unaudited)
The company operates on a calendar year basis. The following table sets forth
selected unaudited historical operating results for each quarter of 1999, 1998
and 1997.
First Quarter Second Quarter Third Quarter Fourth Quarter
------------- -------------- ------------- --------------
(in thousands, except per share amounts)
1999:
Total revenue $ 168,201 $ 186,195 $ 219,779 $ 217,700
Income from operations 15,980 13,786 16,975 15,150
Net earnings 9,035 7,763 9,725 10,544
Earnings per share 0.42 0.36 0.45 0.50
1998:
Total revenue $ 153,837 $ 161,334 $ 170,158 $ 193,925
Income from operations 14,875 13,915 17,603 2,840*
Net earnings 8,544 7,497 9,616 151*
Earnings per share 0.39 0.35 0.45 0.01*
*Includes $8.8 million, or 41 cents per share, non-cash write-down of certain
oil and gas properties.
First Quarter Second Quarter Third Quarter Fourth Quarter
------------- -------------- ------------- --------------
(in thousands, except per share amounts)
1997:
Total revenue $ 43,879 $ 40,259 $ 98,182 $ 131,342
Income from operations 15,629 12,742 15,573 14,495
Net earnings 8,586 6,762 8,644 8,367
Earnings per share 0.39 0.31 0.40 0.39
(14) SUBSEQUENT EVENTS
In January 2000, the Company announced that it had reached a definitive
agreement, subject to certain conditions to closing including regulatory
approval, to acquire 100% of Indeck Capital, Inc. a privately-held independent
power company that owns and operates certain independent power facilities, and
has direct or indirect investments in other independent power facilities. The
proposed purchase price consists of $36 million of common stock and $4 million
of preferred stock. As of January 1, 2000, Indeck Capital, Inc.'s net megawatt
interest in operating facilities or development projects is approximately 240
megawatts, which are primarily concentrated in hydro-electric and gas-fired
generating facilities.
In December 1999, Black Hills Generation, Inc. acquired a 50% interest in a
limited liability company that is constructing three gas-fired combustion
turbine peaking units that have a total capacity of approximately 111 megawatts.
These facilities are scheduled to become operational in the second quarter of
2000, and the production has been sold to Public Service of Colorado under a
seven year tolling arrangement. Ultimately, upon closure of the contemplated
Indeck Capital, Inc. acquisition in 2000, the independent energy business unit
will control 100% of these three facilities as Indeck Capital, Inc. currently
owns the other 50% interest. At December 31, 1999, the Company had funded
approximately $52 million of the expected $80 million capital requirements
associated with these three peaking units through notes receivable from the
limited liability company. Such notes receivable are recorded in the
Consolidated Balance Sheets in Receivables, Other. Management and Indeck
Capital, Inc. expect to close on non-recourse project level financing in the
first quarter of 2000 related to these projects.
FINANCIAL STATISTICS
Years ended December 31, 1999 1998 1997 1996 1995
---- ---- ---- ---- ----
TOTAL ASSETS (in thousands) $674,806 $559,417 $508,741 $467,354 $448,830
PROPERTY AND INVESTMENTS
(in thousands)
Total property and investments $710,488 $619,549 $598,306 $581,537 $557,642
Accumulated depreciation and depletion 246,299 229,942 197,179 181,103 164,383
Capital expenditures (includes AFDC) 104,225 27,225 28,319 24,388 51,895
CAPITALIZATION (in thousands)
Long-term debt $160,700 $162,030 $163,360 $164,691 $166,069
Common stock equity 216,606 206,666 205,403 193,175 182,342
--------- --------- --------- --------- ---------
Total capitalization $377,306 $368,696 $368,763 $357,866 $348,411
======== ======== ======== ======== ========
CAPITALIZATION RATIOS
Long-term debt 42.6% 43.9% 44.3% 46.0% 47.7%
Common stock equity 57.4 56.1 55.7 54.0 52.3
------ ------ ------ ------ ------
Total 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
AVERAGE INTEREST RATE ON LONG-TERM DEBT
8.1% 8.1% 8.1% 8.1% 8.1%
NET INCOME AVAILABLE FOR
COMMON STOCK (in thousands) $37,067 $25,808* $32,359 $30,252 $25,590
DIVIDENDS PAID IN COMMON STOCK
(in thousands) $22,602 $21,737 $20,540 $19,930 $19,312
COMMON STOCK DATA (in thousands)**
Shares outstanding, average 21,445 21,623 21,692 21,660 21,614
Shares outstanding, end of year 21,372 21,578 21,705 21,675 21,638
Earnings per average share, in dollars $1.73 $1.19* $1.49 $1.40 $1.19
Dividends paid per share, in dollars $1.04 $1.00 $0.95 $0.92 $0.89
Book value per share, end of year, in dollars $10.14 $9.58 $9.46 $8.91 $8.43
RETURN ON COMMON STOCK EQUITY (year-end)
17.1% 12.5%* 15.8% 15.7% 14.0%
ALLOWANCE FOR FUNDS USED
DURING CONSTRUCTION AS
PERCENT OF NET INCOME 0.5% 0.9% 0.6% 1.2% 22.9%
*Includes impact of $8.8 million, or 41 cents per average share, write down of
certain oil and gas properties.
**Common Stock Data reflects the 3-for-2 stock split on March 10, 1998.
ELECTRIC OPERATION STATISTICS
Years ended December 31, 1999 1998 1997 1996 1995
---- ---- ---- ---- ----
ELECTRIC ENERGY GENERATED AND
PURCHASED (megawatt hours)
Generated, net station output 1,828,465 1,870,247 1,803,350 1,659,671 1,320,630
Purchased and net interchange 624,662 500,319 503,242 380,106 473,175
----------- ----------- ---------- ---------- ----------
Total generated and purchased 2,453,127 2,370,566 2,306,592 2,039,777 1,793,805
Company use and losses (87,410) (76,131) (94,633) (80,106) (87,512)
----------- ----------- ----------- ----------- -----------
Total electric energy sales 2,365,717 2,294,435 2,211,959 1,959,671 1,706,293
========= ========= ========= ========= =========
ELECTRIC ENERGY SALES
(megawatt hours)
Residential 393,151 392,637 392,059 406,658 383,929
General and commercial 564,286 561,292 547,624 541,463 513,854
Industrial 521,073 527,157 556,554 555,601 552,829
Public authorities 23,295 24,356 22,583 25,083 23,164
Sales for resale 418,200 417,889 413,527 181,766 171,942
---------- ---------- ---------- ---------- ----------
Total firm electric energy sales 1,920,005 1,923,331 1,932,347 1,710,571 1,645,718
Non-firm sales 445,712 371,104 279,612 249,100 60,575
---------- ---------- ---------- ----------- -----------
Total electric energy sales 2,365,717 2,294,435 2,211,959 1,959,671 1,706,293
========= ========= ========= ========= =========
ELECTRIC REVENUE (in thousands)
Residential $ 32,667 $ 32,336 $ 32,178 $ 33,230 $ 30,433
General and commercial 42,619 42,221 41,452 41,307 37,663
Industrial 25,043 25,713 26,802 26,915 26,495
Public authorities 1,878 1,944 1,843 1,970 1,775
Sales for resale 15,686 15,782 16,181 8,189 7,625
---------- ---------- ---------- ---------- ----------
Total firm electric revenue 117,893 117,996 118,456 111,611 103,991
Non-firm electric revenue 9,891 6,002 3,760 2,985 741
Other electric revenue 5,438 5,238 4,281 4,122 4,051
----------- ----------- ----------- ----------- -----------
Total electric revenue $133,222 $129,236 $126,497 $118,718 $108,783
======== ======== ======== ======== ========
ELECTRIC CUSTOMERS (end of year)
Residential 47,571 46,967 46,656 46,146 45,886
General and commercial 9,949 9,703 9,431 9,280 8,958
Industrial 43 44 39 37 35
Public authorities 144 140 141 137 138
Other electric utilities 2 2 2 1 1
---------- ---------- --------- ---------- ----------
Total electric customers 57,709 56,856 56,269 55,601 55,018
========== ========== ========= ========== ==========
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No change of accountants or disagreements on any matter of accounting principles
or practices or financial statement disclosure have occurred.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the directors of the Company is incorporated herein by
reference to the Proxy Statement for the Annual Shareholders' Meeting to be held
June 20, 2000.
EXECUTIVE OFFICERS OF THE COMPANY
The following is a list of all executive officers of the Company. There are no
family relationships among them. Officers are normally elected annually.
Daniel P. Landguth, 53, Chairman and Chief Executive Officer of
Black Hills Corporation
Mr. Landguth was elected to his present position in January 1991.
Roxann R. Basham, 38, Vice President - Finance and Secretary/Treasurer
Ms. Basham was elected to her present position in December 1997.
She had served as Secretary/Treasurer since 1993.
David R. Emery, 37, Vice President - Fuel Resources
Mr. Emery was elected to his present position in January 1997. He had
served as General Manager of Black Hills Exploration and Production since
June 1993.
Gary R. Fish, 41, President and Chief Operating Officer of Independent Energy
Business Unit
Mr. Fish was elected to his present position in September 1999. He had
served as Vice President - Corporate Development since 1996 and as
Controller since 1988.
Everett E. Hoyt, 60, President and Chief Operating Officer of Black Hills Power
Mr. Hoyt was elected to his present position in October 1989.
James M. Mattern, 45, Senior Vice President - Corporate Administration and
Assistant to the CEO
Mr. Mattern was elected to his present position in September 1999. He had
served as Vice President - Corporate Administration and Assistant to the CEO
since 1997 and as Vice President - Corporate Administration since January
1994.
Thomas M. Ohlmacher, 48, Vice President - Power Supply
Mr. Ohlmacher was elected to his present position in August 1994. He had
served as Director of Power Generation since 1993.
Ronald D. Schaible, 55, Senior Vice President and General Manager of
Communications
Mr. Schaible was elected to his present position in July 1999. Previously,
Mr. Schaible had served as Vice-President and General Manager for Brooks
Fiber Properties, Inc. since 1995.
Mark T. Thies, 36, Controller
Mr. Thies was elected to his present position in May 1997. Previously,
Mr. Thies had served in a number of accounting positions, most recently as
Assistant Controller, at InterCoast Energy Company, a wholly owned
subsidiary of MidAmerican Energy Holdings Company since 1990.
Kyle D. White, 40, Vice President - Marketing and Regulatory Affairs
Mr. White was elected to his present position in July 1998. He had served as
Vice President - Energy Services since January 1998 and had served as
Director of Strategic Marketing and Sales since 1993.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding management remuneration and transactions is incorporated
herein by reference to the Proxy Statement for the Annual Shareholders' Meeting
to be held June 20, 2000.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding the security ownership of certain beneficial owners and
management is incorporated herein by reference to the Proxy statement for the
Annual Shareholders' Meeting to be held June 20, 2000.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions is
incorporated herein by reference to the Proxy Statement for the Annual
Shareholders' Meeting to be held June 20, 2000.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements
Financial statements required by Item 14 are listed in the index
included in Item 8 of Part II.
2. Schedules
All schedules have been omitted because of the absence of the
conditions under which they are required or because the required
information is included elsewhere in the financial statements
incorporated by reference in the Form 10-K.
3. Exhibits
*3(a)Restated Articles of Incorporation dated May 24, 1984
(Exhibit 3(I) to Form 8-K dated June 7, 1994, File No.
1-7978).
*3(b)Bylaws dated April 20, 1999. (Exhibit 4(b) to Form S-8
dated July 13, 1999.)
*4(a)Reference is made to Article Fourth (7) of the Restated
Articles of Incorporation of the Company (Exhibit 3(a)
hereto).
*4(b)Indemnification Agreement and Company and Directors' and
Officers' indemnification insurance (Exhibit 4(b) to Form
10-K for 1987).
*4(c)Indenture of Mortgage and Deed of Trust, dated September 1,
1941, and as amended by supplemental indentures (Exhibit B
to Form A-2, File No. 2-4832); (Exhibit 7-B to Form S-1,
File No. 2-6576); (Exhibit 7-C to Form S-1, File No.
2-7695); (Exhibit 7-D to Form S-1, File No. 2-8157);
(Exhibit 4.05(e) to Form S-3, File No. 33-54329); (Exhibit
4-I to Form S-1, File No. 2-9433); (Exhibit 4-H to Form S-1,
File No. 2-13140); (Exhibit 4-I to Form S-1, File No.
2-14829); (Exhibits 4-J and 4-K to Form S-1, File No.
2-16756); (Exhibits 4-L, 4-M, and 4-N to Form S-1, File No.
2-21024); (Exhibits 2(q), 2(r), 2(s), 2(t), 2(u), and 2(v)
to Form S-7, File No. 2-57661); (Exhibit 4.05(t), 4.05(u)
and 4.05(v) to Form S-3, File No. 33-54329); (Exhibit 4(b)
to Form S-3, File No. 2-81643); (Exhibit 4.05(x), 4.05(y),
and 4.05(z) to Form S-3, File No. 33-54329); (Exhibit 4(d)
and 4(e) to Post-Effective Amendment No. 1 to Form S-8, File
No. 33-15868); and (Exhibit 4.05(ac), 4.05(ad), and 4.05(ae)
to Form S-3, File No. 33-54329).
*4(d)Indentures of Trust dated as of June 1, 1992, City of
Gillette, Campbell County, Wyoming; Lawrence County, South
Dakota; Pennington County, South Dakota; Weston County
Wyoming; and Campbell County, Wyoming; to Norwest Bank
Minnesota, National Association, as Trustee (Exhibits 10(n),
10(q), 10(s), 10(u), and 10(w), to Form 10-K for 1992).
*10(a) Agreement for Transmission Service and The Common Use of
Transmission Systems dated January 1, 1986, among the
Company, Basin Electric Power Cooperative, Rushmore Electric
Power Cooperative, Inc., Tri-County Electric Association,
Inc., Black Hills Electric Cooperative, Inc. and Butte
Electric Cooperative, Inc. (Exhibit 10(d) to Form 10-K for
1987).
*10(b) Restated and Amended Coal Supply Agreement for NS #2 dated
February 12, 1993 (Exhibit 10(c) to Form 10-K for 1992).
*10(c) Coal Leases between Wyodak Resources Development Corp. and
the Federal Government -Dated May 1, 1959, (Exhibit 5(i) to
Form S-7, File No. 2-60755) -Modified January 22, 1990
(Exhibit 10(h) to Form 10-K for 1989) -Dated April 1, 1961
(Exhibit 5(j) to Form S-7, File No. 2-60755) -Modified
January 22, 1990 (Exhibit 10(i) to Form 10-K for 1989)
-Dated October 1, 1965 (Exhibit 5(k) to Form S-7, File No.
2-60755) -Modified January 22, 1990 (Exhibit 10(j) to Form
10-K for 1989)
*10(d) Further Restated and Amended Coal Supply Agreement dated
May 5, 1987 between Wyodak Resources Development Corp. and
Pacific Power & Light Company (Exhibit 10(k) to Form 10-K
for 1987).
*10(e) Second Restated and Amended Power Sales Agreement dated
September 29, 1997, between PacifiCorp and the Company
(Exhibit 10(e) to Form 10-K for 1997).
*10(f) Coal Supply Agreement for Wyodak Unit #2 dated February 3,
1983, and Ancillary Agreement dated February 3, 1982,
between Wyodak Resources Development Corp. and Pacific Power
& Light Company and the Company (Exhibit 10(o) to Form 10-K
for 1983). Amendment to Agreement for Coal Supply for Wyodak
#2 dated May 5, 1987 (Exhibit 10(o) to Form 10-K for 1987).
*10(g) Third Restated Electric Power and Energy Supply and
Transmission Agreement dated January 1, 1998, by and between
the Company and the City of Gillette, Wyoming (Exhibit 10(g)
to Form 10-K for 1997).
*10(h) Reserve Capacity Integration Agreement dated May 5, 1987,
between Pacific Power & Light Company and the Company
(Exhibit 10(u) to Form 10-K for 1987).
*10(i) Compensation Plan for Outside Directors (Exhibit 10(bb) to
Form 10-K for 1992).
*10(j) The Amended and Restated Pension Equalization Plan of
Black Hills Corporation dated January 27, 1995 (Exhibit 10
(ad) to Form 10-K for 1994).
*10(k) The Amended and Restated Pension Plan of Black Hills
Corporation (Exhibit 10 (ad) to Form 10-K for 1994).
*10(l) Agreement for Supplemental Pension Benefit for Everett E.
Hoyt dated January 20, 1992 (Exhibit 10(gg) to Form 10-K for
1992).
*10(m) Power Integration Agreement, dated September 9, 1994,
between the Company and Montana-Dakota Utilities Co., a
Division of MDU Resources Group, Inc. (Exhibit 10(gg) to
Form 8-K dated September 12, 1994, File No. 1-7978).
*10(n) Change in Control Agreements dated January 30, 1996 for
Daniel P. Landguth, Everett E. Hoyt, Thomas M. Ohlmacher,
James M. Mattern, Roxann R. Basham and Gary R. Fish (Exhibit
10(af) to Form 10-K for 1995). Change in Control Agreement
dated February 1, 1997 for David R. Emery (Exhibit 10(p) to
Form 10-K for 1997). Change in Control Agreement dated May
1, 1997 for Mark T. Thies (Exhibit 10(q) to Form 10-K for
1997). Change in Control Agreement dated December 31, 1997
for Kyle D. White (Exhibit 10(r) to Form 10-K for 1997).
*10(o) Marketing, Capacity and Storage Service Agreement between
Black Hills Corporation and PacifiCorp dated September 1,
1995 (Exhibit 10(ag) to Form 10-K for 1995).
*10(p) Black Hills Corporation 1996 Stock Option Plan (Exhibit
10(s) to Form 10-K for 1997).
*10(q) The Outside Directors Stock Based Compensation Plan
(Exhibit 10(t) to Form 10-K for 1997).
*10(r) Assignment of Mining Leases and Related Agreement
effective May 27, 1997, between Wyodak Resources Development
Corp. and Kerr-McGee Coal Corporation. Included in this
Agreement are coal leases between Wyodak Resources
Development Corp. and the Federal Government and the State
of Wyoming, as modified by the decision dated May 27, 1997
from the U.S. Department of the Interior - Bureau of Land
Management (Exhibit 10(u) to Form 10-K for 1997).
*10(s) Officers Short-Term Incentive Plan.
10(t) Rate Freeze Extension
21 Subsidiaries of the Registrant.
23a Consent of Independent Public Accountants with respect to
Annual Report on Form 10-K.
23b Consent of Independent Public Accountants with respect to
Annual Report on Form 11-K.
27 Financial Data Schedule.
99 Annual Report on Form 11-K of the Black Hills Corporation
Employee Stock Purchase Plan for the year ended December 31,1999.
* Exhibits incorporated by reference.
(c) See (a) 3. above.
(d) See (a) 2. above.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BLACK HILLS CORPORATION
By DANIEL P. LANDGUTH
Daniel P. Landguth, Chairman,
President and Chief Executive Officer
Dated: March 10, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
DANIEL P. LANDGUTH Director and Principal March 10, 2000
- ---------------------------------- Executive Officer
Daniel P. Landguth, Chairman,
President, and Chief Executive
Officer
ROXANN R. BASHAM Principal Financial Officer March 10, 2000
- ----------------------------------
Roxann R. Basham, Vice President-Finance,
and Corporate Secretary/Treasurer
MARK T. THIES Principal Accounting Officer March 10, 2000
- ----------------------------------
Mark T. Thies, Controller
ADIL M. AMEER Director March 10, 2000
- ----------------------------------
Adil M. Ameer
BRUCE B. BRUNDAGE Director March 10, 2000
- ----------------------------------
Bruce B. Brundage
DAVID C. EBERTZ Director March 10, 2000
- ----------------------------------
David C. Ebertz
JOHN R. HOWARD Director March 10, 2000
- ----------------------------------
John R. Howard
EVERETT E. HOYT Director and Officer March 10, 2000
- ----------------------------------
Everett E. Hoyt (President and Chief
Operating Officer of Black Hills Power)
KAY S. JORGENSEN Director March 10, 2000
- ----------------------------------
Kay S. Jorgensen
DAVID S. MANEY Director March 10, 2000
- ----------------------------------
David S. Maney
THOMAS J. ZELLER Director March 10, 2000
- ----------------------------------
Thomas J. Zeller
BOARD OF DIRECTORS AND OFFICERS
BOARD OF DIRECTORS
Daniel P. Landguth John R. Howard
Chairman of the Board and President
Chief Executive Officer of the Company Industrial Products, Inc.
Adil M. Ameer Everett E. Hoyt
President and Chief Executive Officer President and Chief Operating Officer
Rapid City Regional Hospital Black Hills Power and Light Company
Bruce B. Brundage Kay S. Jorgensen
President and Director Owner - Jorgensen-Thompson
Brundage & Company Creative Broadcast Services
David C. Ebertz David S. Maney
President Co-founder
Risk Management Consulting Worldbridge Broadband Services
Thomas J. Zeller
President
RE/SPEC Inc.
CORPORATE OFFICERS
Daniel P. Landguth James M. Mattern
Chairman of the Board and Senior Vice President-Corporate
Chief Executive Officer of the Company Administration and Assistant to
the CEO
Roxann R. Basham Thomas M. Ohlmacher
Vice President - Finance and Vice President-Power Supply
Corporate Secretary/Treasurer
David R. Emery Ronald D. Schaible
Vice President - Fuel Resources Senior Vice President and General
Manager-Communications Business Unit
Gary R. Fish Mark T. Thies
President and Chief Operating Officer- Controller
Independent Energy Business Unit
Everett E. Hoyt Kyle D. White
President and Chief Operating Officer Vice President-Marketing and
Black Hills Power and Light Company Regulatory Affairs